Method and apparatus for a monodiameter wellbore, monodiameter casing, monobore, and/or monowell

ABSTRACT

An assembly and methods for constructing a MONOWELL includes a monodiameter casing disposed in a monodiameter wellbore having diametric efficiency with a monobore production delivery system disposed within the monodiameter casing. An assembly for constructing a monodiameter wellbore includes a bottomhole assembly having a overgauge hole drilling member, a directional steering assembly, a measurement while drilling tool, and a logging while drilling tool; a work string attached to the bottomhole assembly and extending to the surface; drilling fluids flowing through the work string and bottomhole assembly; chemical casing casing the borehole; expandable casing disposed in the wellbore; and a sealing composition disposed between the expandable casing and the wellbore.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a divisional of U.S. patent application Ser.No. 11/656,223 filed Jan. 22, 2007 entitled Method and Apparatus for aMonodiameter Wellbore, Monodiameter Casing, Monobore, and/or Monowell,which is a divisional of U.S. patent application Ser. No. 11/153,046filed Jun. 15, 2005 entitled Method and Apparatus for a MonodiameterWellbore, Monodiameter Casing, Monobore, and/or Monowell, now U.S. Pat.No. 7,225,879, which is a continuation of U.S. application Ser. No.10/293,013 filed Nov. 13, 2002 and entitled Method and Apparatus for aMonodiameter Wellbore, Monodimater Casing and Monobore, and furtherclaims the benefit of 35 U.S.C. 119(e) of U.S. provisional applicationSer. No. 60/335,132 filed Nov. 14, 2001 and entitled Monodiameter WellArchitecture and Construction and U.S. provisional patent applicationSer. No. 60/414,517, filed Sep. 27, 2002 and entitled Method andApparatus for a Monodiameter Wellbore, Monodiameter Casing and Monobore,all hereby incorporated herein by reference in their entirety. Thepresent application is related to U.S. patent application Ser. No.10/170,400 filed Jun. 13, 2002 and entitled Methods of ConsolidatingFormations or Forming Chemical Casing or Both While Drilling, now U.S.Pat. No. 6,702,044; U.S. patent application Ser. No. 10/006,109 filedDec. 4, 2001 entitled Resilient Cement, now U.S. Pat. No. 6,668,928;U.S. patent application Ser. No. 10/177,568 filed Jun. 21, 2002 entitledMethods of Sealing Expandable Pipe in Well bores and SealingCompositions, now U.S. Pat. No. 6,722,433; U.S. patent application Ser.No. 10/243,001 filed Sep. 13, 2002 entitled Methods and Compositions forSealing An Expandable Tubular in A Well Bore; all hereby incorporatedherein by reference.

BACKGROUND OF THE INVENTION

The present invention relates to constructing a MONOWELL and moreparticularly to apparatus and methods for constructing a monodiameterwellbore for a monodiameter casing and a monobore production deliverysystem and still more particularly to drilling and completing a wellusing apparatus and methods to achieve a monodiameter wellbore,installing monodiameter casing and liners and installing a fullboreproduction delivery system.

Traditional well construction, such as the drilling of an oil or gaswell, includes a wellbore or borehole being drilled through a series offormations. Each formation, through which the well passes, must besealed so as to avoid an undesirable passage of formation fluids, gasesor materials out of the formation and into the borehole or from theborehole into the formation. In addition, it is commonly desired toisolate both producing and non-producing formations from each other soas to avoid contaminating one formation with the fluids from anotherformation.

As the well is drilled deeper, conventional well architecture includescasing the borehole to isolate or seal each formation. The formation mayalso be cased for borehole stability due to the geo-mechanics of theformation such as compaction forces, seismic forces and tectonic forces.The casings prevent the collapse of the borehole wall and prevent theundesired outflow of drilling fluids into the formation or the inflow offluids from the formation into the borehole. The borehole may need to becased due to equivalent circulating density and hydraulics reaching orexceeding the formation pore pressure or exceeding the fracture gradientpressure thus allowing fluids or gases to transfer between formationsand borehole. If the formations are non-producing, or not of the desiredproducing interval, (some intervals are producing but at low levels) theformations can be cased together. If shallow water flows (where waterflows several hundred feet below the seabed floor), or if there ispotential communication among formations, then the formation is cased.The casings extend downhole and are sequentially placed across theformations through which the wellbore or borehole passes. The casingsmay be liners which do not extend to the surface of the wellbore.Traditionally steel casing has been used to case off formations.

In standard practice, each succeeding casing placed in the wellbore hasan outside diameter significantly reduced in size when compared to thecasing previously installed, particularly to accommodate hangers for theinner strings, and may be described as a series of nested casingstrings. The borehole is drilled in intervals whereby a casing, which isto be installed in a lower borehole interval, is lowered through apreviously installed casing of an upper borehole interval. As aconsequence of this procedure, the casing of the lower interval has asmaller diameter than the casing of the upper interval. Thus, thecasings are in a nested arrangement with casing diameters decreasing inthe downward direction.

The use of a series of casings, which have sequentially reduceddiameters is derived from long experience. The number of casingsrequired to reach a given target depth is determined principally by theproperties of the formations penetrated and by the pressures of thefluids contained in the formations. If the driller encounters anextended series of high pressure/low pressure intervals, the number ofliners required under such circumstances may be such that the wellcannot usefully be completed because of the continued reduction of thecasing diameters required. Along with the downsize serial casingoperations, the production tubulars may have to be downsized as wellfurther reducing the delivery capacity of the well.

If the borehole extends through a formation that tends to cave in andthus causes the borehole to be very unstable, casing inserts must beinstalled to keep the borehole open. A casing insert is a type ofemergency casing string which shores up an unstable formation and is anadditional section of casing that is set through this unstable portionof the borehole. By requiring a casing insert for this unstableformation, an even smaller size casing than was planned is then requiredto complete the well. This reduces the diameter of the well and thus theultimate internal diameter available for the production tubulars. Thecasing insert may not be possible, requiring that the well besidetracked, resulting in a substantial reduced diameter wellbore.

The disadvantages of nesting casing and liners is apparent in slim-holedrilling. A slim-hole well is one in which 90% or more of the length ofthe well is drilled with bits smaller than 7 inches in diameter. See SPE19525: An Innovative Approach to Exploration and Exploitation Drilling:The Slim-Hole High-Speed Drilling System by Walker and Millheim,September 1990. Slim hole drilling focuses on starting with a smallborehole and finishing with an even smaller borehole for production.

The casing is fixed in the borehole by a cement layer between the outerwall of the casing and the wall of the borehole. During the drilling ofthe wellbore, annuli are provided between the outer surfaces of thecasings and the borehole wall and a composition, sometimes referred toas “oil field” cement, is introduced in the annulus for cementing thecasing within the wellbore. The casing is commonly cemented in placeafter the installation of each casing. When the casing is located in itsdesired position in the well, a cement slurry is pumped via the interiorof the casing and around the lower end of the casing and upwards intothe annulus, thereby causing the cement slurry to drive the drillingfluid upward in the annulus. As soon as the annulus around the casing issufficiently filled with the cement slurry, injection of cement into thewell is stopped and the cement slurry is allowed to harden. The cementsets up in the annulus, supporting and positioning the casing andforming a substantially impermeable barrier which divides the well boreinto subterranean zones.

Ultimately the borehole reaches the target and is drilled through ahydrocarbon-containing formation or reservoir to produce hydrocarbons.The borehole may not be cased through the hydrocarbon-containingreservoir to allow substantially unrestricted influx of fluids from theformation into the borehole. When the formation is so weak that it willcollapse, the uncased borehole section is completed with a liner. It iscommon practice to install a liner in the reservoir by suspending theliner in the borehole through the reservoir and then pumping a cementslurry into the annulus. After the cement has set to a hardened mass,perforations are extended through the liner and the cement body into thehydrocarbon-containing formation around the well in order to allowin-flow of reservoir hydrocarbon fluids, such as oil or gas, into thewell.

The liner may be provided with slots to allow fluid influx into theborehole. The liner is usually secured at its upper end to the lower endof the non-productive barrier casing previously installed in theborehole. Because the slotted liner must pass through the previously setcasing, it must have an outer diameter which is less than the innerdiameter of the cased section. Over time, the formation may collapse andsettle against the outer wall of the liner so that the area around theliner gets filled with particulates. U.S. Pat. Nos. 5,366,012 and5,667,011 teach an expandable liner which is expanded by an expansionmandrel by moving the mandrel through the liner to radially expand theliner to a larger diameter in the borehole.

The purpose of the cement body around the casing is to fix the casing inthe well and to seal the borehole around the casing in order to preventvertical flow of fluid alongside the casing towards other formationlayers or even to the earth's surface. Casing is traditionally cementedin place for two main reasons. (i) one to seal off and prevent leakpaths between permeable zones and/or surface, and (ii) to give supportand stability to the casings. The cement prevents fluid exchange betweenor among formation layers through which the wellbore passes, andprevents the undesirable migration of fluids between zones or gas fromrising up the wellbore. It is important that there is no gas or fluidleakage after the cement has set and the well is completed.

A problem generally encountered during cementation of the casing is,that due to various factors, such as the existence of varying pressureand temperature gradients along the length of the casing and shrinkageof the cement body during hardening thereof, relative displacementsoccur between the casing and the hardened cement mass which may resultin poor bonding or cracking between the cement body and the casing. Poorbonding may result in the presence of a so-called micro-annuli betweenthe casing and cement body, micro-annuli may extend along a substantialpart of the length of the casing. The occurrence of a micro-annuli isparticularly dangerous in gas wells as substantial amounts of gas mightescape to the surface. In some cases hydrogen sulfide or natural gas canescape into the atmosphere. This condition may also lead to surface orground water contamination. The resulting problems are very expensive tocorrect.

The poor bonding of the cement may be attributed to drilling fluidcontamination or to bonding of the cement to the casing after the cementhas set and/or oil or mill finish contamination on the surface of thecasing or it can be attributed to aggressive drilling or aggressivepressure subjection and large pressure differs prior to it hardening andduring the operation. As is well known in the art, hardening of cementcauses generally a slight reduction of the volume of the cement. A morefundamental cause is the loss of hydrostatic head during the curing ofthe cement such that the formation pressure exceeds the annulus pressureand gas migration occurs causing channeling of the cement and subsequentleakage. Various additives and application techniques relative to thecement have been used in order to reduce the occurrence of this problem.During cementing operations, it is common to both reciprocate and rotatethe casing during the cement pumping operation to break up or close anycement channels around the casing. Also compressible cement slurrieshave additives that entrain gas, which during the cement pumpingoperation, are compressed and as the hydrostatic head is lost duringcuring of the cement, the entrained gas subsequently expands andprevents loss of the pore pressure such that formation gas is preventedfrom migrating into the annulus. This technique, however, results in alower strength cement. Thixotropic cement slurries depend on the cementachieving high gel strengths in very short time periods. If there is arapid static gel strength obtained, gas migration and channeling arereduced or prevented. These specialized cement additives are expensiveand require specific operational techniques. Thus, it is essential thata good bonding be created between the cement body and both the casingand the borehole wall.

There are various types of wells such as land based wells and offshorewells. Well applies to anything that produces oil, gas, water, orhydrates. Offshore wells may be shallow or deep water wells. A shallowoffshore well is typically drilled from a platform that is in water upto 3,000 feet in depth. A deep water well is drilled from a floatingplatform or vessel with a riser extending from the sea floor to theplatform or submersible rig. Any water deeper than 5,000 feet requires adrilling vessel, typically a drill ship.

Various types of casing may be installed in the well including conductorcasing, surface casing, intermediate or production casing and productionliners. Typically a land based well starts with a 20″/18⅝″ or largerdiameter casing and telescopes down through two or three intermediatecasings, to a final casing size of typically 6⅜″ with a 5″ productionliner installed. Each casing is secured in place with cement filling anannulus having a size typically varying from 1 to 10 inches over thelength of the casing and may be as much as 14 to 21 inches or greater ata wash out in the borehole wall.

FIG. 1 is a schematic of a conventional deep water well completion. Thesize and number of casing and tubing strings will increase or decreasedepending upon the well plan based upon, for example, the depth of thewell, the production tubing delivery size, the structural support andthe seabed formation support. If the seabed formation is unconsolidatedand has little support, then the structural or conductor casing islarger and is set deeper. If the initial conductor casing is in rock,then it can be smaller with substantially less depth. For example,initially a structural or conductor casing and riser are lowered from adrilling platform and driven, drilled or jetted into the sea floor toprovide support for a surface casing. The structural or conductor casingmay or may not be cemented.

FIG. 1 illustrates a 36 inch by 16 inch by 10¾ inch by 7 inch casingprogram with the addition of one or more tubing strings. After the 36inch conductor casing is set, one or more surface casings is installed.A borehole is drilled for a 20 inch surface casing which is lowered intoplace with a 21″ surface casing riser attached thereto. A subseawellhead with blowout prevention equipment, such as an 18¾ inch blowoutpreventer, is installed on the surface casing. The subsea wellhead maybe supported by a structural casing.

Further, a borehole may be drilled through the riser and wellhead andthrough a problematic formation to extend a structural casing throughthe problem formation. For example, there are salt formations in thedeepwater of the Gulf of Mexico. The structural casing forms a barrieracross the formation while also supporting the wellhead. The structuralcasing has a thicker wall and provides a stable support frame for andcan carry the load on the subsea wellhead. A 16 inch structural casingmay be drilled, installed and cemented through a salt formation to sealoff the salt formation from the wellbore being drilled. It should beappreciated that if there is no problematic formation, such as a saltzone, a shallow water flow zone, loss circulation zone, or other problemzone, then a structural casing is not needed to seal off the problematicarea but it will support the subsea or platform wellhead, depending onwell type.

Another borehole is then drilled for a 13⅜ inch intermediate casingstring which is lowered into the borehole, attached to another riser,and cemented in place. Next a borehole may be drilled for anotherintermediate casing, such as a 11⅞ inch casing, and cemented in place.The borehole for the production casing string, such as a 9⅝ inch casing,is drilled and the production string is landed. It may or may not becemented in place. The drilling is performed through blowout preventionequipment.

Subsequently, a production tubing is installed and is supported withinthe wellhead on a tubing hanger, a hanger system or anchor system. Theproduction tubing is typically 3½ inch tubing but may be as small as 1½inches or as large as 12 inches. After the tubing hanger seals have beentested, the blowout prevention equipment is removed and a Christmas treeor subsea tree is installed. If the well is land based or being drilledfrom a platform, the blowout prevention equipment is at the surface. Ifthe well is a subsea well, the blowout prevention equipment and tree areinstalled subsea. Also, the tubing can be installed through the subseatree or subsea template. Thus, conventional techniques use a pluralityof concentric casing strings with varying diameter and do not have amonodiameter architecture. It should be appreciated that conventionalwell architectures may vary depending upon the geological or drillingconditions.

As a consequence of the nested arrangement of the casings, a relativelylarge diameter borehole is required at the upper part of the borehole.Because the upper casing(s) has to be larger than the lower casing(s)for the lower casing(s) to pass through the upper casing(s), the upperportion of the borehole typically has a much larger diameter than theintended ultimate diameter at the bottom of the borehole. Largeboreholes are disadvantageous in that they generate large amounts ofcuttings and require increased volumes of drilling fluid and cement. Inthe standard well casing configuration, large volumes of cuttings areproduced initially and heavy logistics are required during early phasesof drilling. Generally speaking, larger borehole sizes take longer todrill than smaller diameter boreholes at equivalent depth. For example,increased drilling rig time is involved due to required cement pumpingand cement hardening. Further, a large borehole diameter often takeslarger fluid and horsepower capacity rigs generating increased costs dueto heavy casing handling equipment and large drill bits. Thusconventional equipment results in larger boreholes drilled for eachformation, larger sized equipment, greater fluid volumes, and largercasing strings than is absolutely required to provide a borehole for awell, for an injecting or producing or monitoring.

Utilizing a large borehole often causes the usage of a wide variety ofequipment and fluids that might not achieve maximum efficiency for thedrilled borehole. If problems arise, additional fluids must be pumpedand additional cement must be used to cement the formation to overcomethe variances encountered during conventional well construction,otherwise a side track must be performed.

Conventional well architecture, engineering, and planning accounts forpotential problem migration, well plan variance, and contingency.Therefore, large tolerances in equipment and procedures are provided inanticipation of variances in the length and/or composition of theformations, geomechanics, and growth/loading design. Compensation in thewell architecture, engineering, and planning must be included in thewell plan for contingency due to such large tolerances, includingdrilling for additional casing strings for geomechanical problems andsidetracks and re-drills for the installation of casing inserts prior toreaching the reservoir formation.

It can be appreciated that the problems with conventional wellarchitecture are exacerbated in a deepwater well. In addition to thelarger boreholes to be drilled, the larger sized completion equipment,the greater fluid volumes, and the larger casing strings, a deepwaterwell also requires large risers extending to the water's surface. Therisers require the use of additional large fluid volumes, such as fordrilling fluids and cement, to drill and cement the casing strings.Further, the large risers add substantial expense and additional largesized completion equipment.

It has long been an objective to achieve a monodiameter well where thewellbore is drilled from spud to total depth using one borehole size.For example the monodiameter well might be spudded with a drivenconductor 7⅝″ to 9⅝″ in diameter. Thereafter, a borehole is drilled foreach borehole section, perhaps a 7″ diameter. The borehole is then casedor lined with expandable casing or liners. Cement or some otherinnovative sealing composition is then used for the annular pressureseal. The next section of borehole is drilled using the same sizedovergauge hole drilling and then cased or lined again with the same sizeexpandable casing or liner. The process is repeated to target depth. SeeSPE 65184: “Towards a Mono-Diameter Well—Advances in Expanding TubingTechnology” by Benzie, Burge, and Dobson presented at the SPE EuropeanProgram Committee Conference held Oct. 24-25, 2000.

The monodiameter well is designed based on the borehole size requiredacross the reservoir. Rig capacity and all the drilling and completionequipment for the entire well is sized to the reservoir borehole size.Upon the advent of the monodiameter well, the telescoping well designwith all its associated and myriad selection of drilling and completionsequipment will become obsolete. The monodiameter well will achievedramatic reductions in well construction costs. The challenge to theindustry is to develop the full suite of enabling and complimentarytechnologies that will be required to drill and complete a monodiameterwell. This suite of equipment will include drilling equipment, reamingwhile drilling (RWD), bi-center bits, energy balanced bits, near bitreamers, open hole annular sealing, well control procedures, wellcontrol equipment, and wellheads among others.

Expandable tubulars are being developed whereby casings and liners areexpanded diametrically after they are placed in wellbores. The ultimateuse of expanded tubulars is in a monodiameter well, whereby the entirewell is drilled and cased using effectively one hole size. A solid steeltubular can be readily expanded using forces, either mechanical orhydraulic, available on most drilling and workover rigs. Expandabletubulars can be used in open hole either as a temporary drilling lineror as a permanent liner tied back to the previous casing string. See SPE54508: “The Reeled Monodiameter Well” by Pointing, Betts, Bijleveld, andAl-Rawahi, presented at the 1999 SPE/CoTA Coiled Tubing Roundtable, May25-26, 1999, and SPE 65184: “Towards a Mono-Diameter Well—Advances inExpanding Tubing Technology” by Benzie, Burge, and Dobson, presented atthe SPE European Petroleum Conference, Oct. 24-25, 2000.

The concept of expanding a solid tube is relatively simple. A mandrel or“pig” whose outside diameter is greater than the tube's inside diameteris forced through the tube, thereby plastically deforming the tubingmaterial to a larger diameter size. A solid tubular can be expandedusing a cone of ceramic, tungsten carbide or hardened steel that iseither mechanically pulled through the tubular or hydraulically pushed.The solid tubular can be expanded to around 30%-40%, although a rangefrom 10%-20% will probably be more typical. The combination of expansioncone radius, material characteristics, expansion ratio, annular sealmaterial, and gauge tolerance of the open borehole or casing withinwhich the tubular is to be expanded, all determine the expansion forcesand the tolerances or fit of the final expanded tubular in the wellbore.During the expansion process, the tubular strength increases since theexpansion process is a cold working of the material. However, thecollapse strength of a post expanded tubular is less than that of thepre-expanded tubular but it is within the design limits expected for therequired borehole pressures.

One of the requirements of expandable casing/liners is to run a drillbit through the casing and drill a hole of a greater diameter than theprevious casing. The next section of casing will then be run through theprevious one and expanded against it. Thus, an enlarged wellbore havinga diameter greater than the external diameter of the preceding installedcasing must be drilled such as by “overgauge hole drilling” whichencompasses the use of expandable bits, bi-center or eccentric bits orequivalent, reaming while drilling (RWD), under-reamers or similar toolsand other novel drilling methods known to those skilled in the art, suchas expandable/retractable stabilizers. Typical bits for overgauge holedrilling include bi-center bits and eccentric bits. A bi-center bit hasa well-defined pilot bit section and an eccentric wing mounted furtherback on the bit body. An eccentric bit resembles more of a conventionalbit, but a flank on the high-lobe side has a longer profile than on theother side. Eccentric bits are generally used in softer formationswhereas bi-center bits are more commonly used in harder formations. Themajor difference of both bi-center and eccentric bits over under-reamersis that a section of borehole can be drilled to the required size in onerun. However, an under-reamer provides a smoother and more diametricborehole wall.

At a desired depth, or when it is otherwise decided to case or line andcement the wellbore, an expandable casing or liner, whose greatestexternal (outside) diameter approximates, i.e., is only slightly smallerthan the internal diameter of the casing or liner previously installed,is lowered through the previously installed casings or liners and intothe newly drilled open enlarged borehole. The lowered casing or liner isa tubular made of a deformable material. The deformable casing/liner mayhave a decreased wall thickness. The lowered casing/liner is positionedin relation to the wellbore so that the upper end of the loweredcasing/liner overlaps the lower end of the previously installed casing.

In expanding the expandable casing/liner, a die member, such as amandrel or cone, is drawn or pumped through the length of the loweredcasing to expand the casing in-situ. The die member has a suitable shapeand composition, such as hardened steel, and is adapted or sized andshaped to expand the liner to the diameter of the previously installedcasing. The die member is shaped or designed to provide at leastsubstantially uniform expanded or deformed liner segment of circular orapproximately circular periphery.

The upper end of the die member is connected to a running string and ispulled through the casing. Further, the die member may have a fluidtight seal, such as a cupseal, for sealing the die member within thecasing and allowing sufficient fluid pressure to produce movement of thedie member. Any suitable wellbore fluid or liquid available can be usedfor displacing the die member. To ease the expansion process, the insidediameter of the casing may be lubricated to allow the die member orexpansion cone to move smoothly through the casing. The rate of upwardadjustment or movement of the die member by upward movement of therunning string and the application of pressure below the die member maybe correlated so as to reduce movement of the die member up through thecasing with concurrent gradual deformation and expansion of the casing,providing an expansion achieving an external diameter equal to orapproximating, preferably slightly greater or larger than, that of thepreviously installed casing.

Threaded connections of lengths of expandable casing or liner remain theprimary connection of choice. However, the connection has to beinternally flush to allow the die member to pass through the connection,and externally flush to allow expansion to occur with constant expansionforce. SPE 54508: “The Reeled Monodiameter Well” by Pointing, Betts,Bijleveld, and Al-Rawahi, presented at the 1999 SPE/CoTA Coiled TubingRoundtable, May 25-26, 1999, discloses using coiled casing thatmaintains a single diameter of well bore throughout. Coiled casing canbe used in the production of a monodiameter wellbore as well as tubularjointed expandable casing. Coiled casing can be expanded or installednon-expanded. A reeled monodiameter casing or liner has the samethroughbore.

The expansion causes a virtual forced fit at the overlap of the upperend of the expanded lower casing/liner into the lower end of thepreviously installed casing. Thus, hangers are not required since thecasing/liner is supported by the previously installed string. A constantthrough-bore is maintained at the overlap. The well is then subsequentlycompleted by internally cladding the last casing string. Cladding theoverlapped portions of the adjacent casings allows the lower casing tobe supported at the cladding by the upper casing and allows the upperand lower casings to be pressure sealed at the overlap. The pipe overthe area (overlap) to be cladded may include a corrosion resistantcoating. One type of expandable tubular is disclosed in U.S. Pat. No.6,085,838, hereby incorporated herein by reference.

The new well concept of using expandable casing and liners necessitatesa narrow annuli in the range of 3 to 4 inches on diameter or lessbetween the casing/liners and the borehole wall. Thus a quality boreholeand optimum borehole size are required. The wellbore or borehole musthave diametric efficiency. Diametric efficiency is the maintenance ofthe optimum hole size regardless of other well construction requirementsor constraints. Preferably diametric efficiency maintains the optimumborehole size from the surface through the producing reservoir. The useof expandable casing/liners requires the maintenance of diametricefficiency to achieve a monodiameter well. Diametric solutions thatmaintain or improve diametric efficiency in a range of applications frommultilaterals, high pressure/high temperature (HPHT), extended reach,horizontals and deepwater environments and remedial applications (i.e.side tracks) must be developed to use expandables.

Referring now to FIG. 2, there is shown a bell-end design disclosed inthe SPE 54508 article. The annulus is split up into two parts: (i) wherethe liner is expanded against the previous casing/liner, either fulllength or overlap, and (ii) where the casing is expanded over the openborehole section.

The annular clearances between the casing/liner and borehole wall mustallow cement slurries to displace the drilling fluid effectively. Theinterface or overlap between casing/liner strings must have themechanical ability of the interface to hold axial loads and must havethe hydraulic ability to form a pressure tight seal between the twocasing/liner strings.

A simple expansion of metal against metal does not provide a reliableseal. Elastomeric seals are used to provide a pressure seal between theoverlapped casing ends. Inside a previous casing or a gunbarrel holethrough hard formations, a polymer or an elastic rubber coating may beapplied externally to the casing/liner. This can deform elastically withthe expansion of the casing/liner and form a seal between thecasing/liner and/or formation.

A thicker layer of heat softening rubber, which can be coated on theoutside of the expandable pipe, may be used in slightly overgaugeboreholes. The thermal plastic rubber is reformed in-situ to its finalshape by performing the casing/liner expansion process at a moreelevated temperature, achievable by heating the well either before orduring the expansion process.

Previously, a variety of cement compositions have been used forcementing in open hole applications. However, cement is undesirable foruse with expandable casing. Oilfield cement or hydraulic cementcompositions are incompressible and tend to resist the expansion of thecasing or liner making the expansion more difficult. Thus, expansion ofthe casing/liner can lead to the crushing of the cement, and consequentloss of effectiveness regarding the zones. This problem is exacerbatedby the small annular clearance associated with expandable casing/liners.With the new well concepts as described and the narrow annuli created inthe range of 3 to 4 inches on diameter or less, other isolationmaterials must now be considered. Isolation materials must be ductile inorder to form an appropriate seal. Conventional cement will beparticularly brittle and weak in such thin sheaths or thicknesses and ishence an inappropriate sealing medium. Therefore, a composition withcomparable strength to cement, but with greater elasticity andcompressibility is required for cementing expandable casing.

Other problems may be encountered using oilfield cement or hydrauliccement as the sealing composition for expandable casing/liners. If thecement composition gels or sets prior to accomplishing the expansion,the cement composition is crushed in the annular space between the wallsof the well and the expandable casing or liner whereby it does notfunction to seal the expanded casing or liner in the wellbore.

A conventional cement sealant composition under expansion conditions,with appropriate cement recipe to prevent the pre-maturely setting ofthe cement, may be used. Sealant compositions are required for sealingexpandable casings or liners in well bores. Such compositions arecompressible and maintain the properties required to provide a sealbetween the walls of the wellbore and the expanded casings or liners.Several types of sealants materials have been tested. Two materials aresilicon gel and a two-component silicon rubber. Suitable wetting agentsmay be used such as barite or iron micropellets. The silicon gel is ahighly viscous material. The two-component silicon rubber consists oftwo materials mixed in equal volume and weight. The mixture willautomatically set, but a retarder may be added to control setting times.Silicon gels or rubbers are very ductile.

Prior to the expansion, the sealant material may be pumped into theannulus between the walls of the well bore and the unexpanded casing orliner in a similar manner to conventional cementing techniques. Once inplace, the casing is expanded and the material allowed to set. In aseverely washed out borehole, such as soft formations with wash outs andledges, the sealant material may not be adequate.

In the traditional well, the wellbore may be open 3 to 5 days beforestability of the borehole wall becomes a problem. After that, portionsof the borehole wall may start to fall into the borehole. In usingexpandable casing/liners, longer intervals are going to be drilled thusleaving the borehole open for longer than 3 to 5 days. Thus there is amuch longer time period than in conventional drilling during which theborehole wall is unsupported by casing during drilling. It is importantthat the borehole wall remain stable for these longer periods of time.Therefore, special drilling fluids must be used to drill the enlargedboreholes for expandable casing/liners to ensure the stability of theborehole over longer time periods.

Drilling fluid is circulated downwardly through the drill string,through the drill bit and upwardly in the annulus between the walls ofthe well bore and the drill string. The drilling fluid functions toremove cuttings from the well bore and to form a filter cake on theborehole wall. As the drilling fluid is circulated, a filter cake ofsolids from the drilling fluid forms on the walls of the well bore. Thefilter cake build-up is a result of initial fluid loss into permeableformations and zones penetrated by the well bore. The presence of thefilter cake reduces additional fluid loss as the well is drilled.

In addition to removing cuttings from the well bore and forming filtercake on the well bore, the drilling fluid cools and lubricates the drillbit and maintains a hydrostatic pressure against the well bore walls toprevent blow-outs, i.e., to prevent pressurized formation fluids fromflowing into the well bore when formations containing the pressurizedfluids are penetrated. The hydrostatic pressure created by the drillingfluid in the well bore may fracture low mechanical strength formationspenetrated by the well bore which allows drilling fluid to be lost intothe formations. When this occurs, the drilling of the well bore must bestopped and remedial steps taken to seal the fractures. Such remedialactions are time consuming and expensive.

It is preferred to drill as long an interval as possible without havingto stop drilling and case the borehole. However, in order to insure thatfracturing of low mechanical strength formations penetrated by the wellbore and other similar problems do not occur, it may become necessary tocase and cement the borehole. As previously discussed, it is preferredto avoid frequently installing and cementing casing because drillingmust be stopped and frequent casing of the borehole may cause areduction in the producing borehole diameter.

Another problem that occurs in the drilling and completion of well boresis that when the well bore is drilled into and through unconsolidatedweak zones or formations. Unstable materials such as clays, shales, sandstone and the like make up a high percentage of the formations in whichwells are drilled, and a majority of well bore problems are a result ofthe instability of such materials, particularly shale instability.Shales are sedimentary rocks that contain a variety of clays. Shalescontaining montmorillonite, often referred to as smectite clays, swelland disperse when contacted by water. Shales which swell upon contactingwater are often referred to as heaving or sloughing shales. Such shalesupon contact with aqueous drilling fluids swell and fracture renderingthe well bore wall unstable. In such cases, the well bore wall sloughsinto the well bore. Sloughing of shale and other similar unstablematerials into the well bore can cause the drill string to become stuckand can enlarge the well bore resulting in large subterranean cavities.Additionally, when sloughing occurs while the drill bit is being changedat the surface, the well bore fills up and must be cleared beforedrilling can proceed.

Furthermore, the heaving unstable material suspended in the drillingfluid increases its solid content, and as a result, the viscosity of thedrilling fluid increases to the point where the drilling fluid must bechemically treated to reduce its viscosity or it must be dilutedfollowed by the addition of weighting material to maintain its mudweight. The instability of clays, shales, sand stone and the like isalso caused by hydraulic pressure differential leading to fluidtransport and by pressure changes near the well bore as the drillingfluid compresses pore fluid and diffuses a pressure front into theformation.

Consolidating unconsolidated weak zones or formations formed of clays,shales, sand stone and the like while drilling a well bore preventssloughing of the clays, shales, sand stone and the like into the wellbore and prevents the need for implementing time consuming and costlyremedial steps. It is preferred to increase the mechanical strength ofthe well bore whereby hydrostatic pressure exerted on the well bore bythe drilling fluid does not cause fractures or the like to occur in thewell bore. Such fractures cause drilling fluid to be lost and alsorequire stoppage of the drilling operation and costly remedial steps tobe taken.

Another significant advantage of increasing the mechanical strength ofthe well bore is the reduction or elimination of casing intervals atwhich casing or liners are cemented in the well bore which reduces oreliminates the overall time and cost of cementing the well. Anadditional advantage is that the well bore has a larger diameter in theproduction zone, due to fewer casing intervals, which increasesproductivity.

A monobore is a term used in the industry for a fullbore productiondelivery system. OTC 8585: “Case History, Well Completion and ServicingStrategies for the Hibernia Field” by Wylie, Maier, Shamloo, Huffman,and Downton presented at the 1998 Offshore Technology Conference, May4-7, 1998, defines a monobore. To address overall completion criteria, amonobore design was chosen for the Hibernia Field for the initialcompletions. This design allowed flowbore access across the well's payzone without diameter restrictions (not necessarily constant diameter).

In conventional completions, there are internal valves and gauges whichproject into the bore of the completion tubular. These narrow the insidediameter of the completion tubulars. Each restriction in the completiontubulars causes a pressure drop across that point causing scale andcorrosion to occur at these points. The narrowing of the completiontubulars also reduces flow and therefore production.

The present invention overcomes the deficiencies of the prior art

SUMMARY OF THE PREFERRED EMBODIMENTS

The present application is directed to a system to achieve a MONOWELLand provides a total solutions approach to the well construction of amonodiameter wellbore and MONOWELL. The assembly and methods of thepresent invention construct a MONOWELL having monodiameter casing andmonobore throughput. The monodiameter casing is disposed in amonodiameter wellbore having diametric efficiency. The monobore is afullbore production delivery system which either extends through themonodiameter casing from the surface to the formation barrier or extendsthrough the monodiameter casing from the surface and through theproducing formation. A full bore production delivery system will havethe same nominal internal diameter throughout the production conduit nomatter whether the well is an injection well or a producing well. Fullbore production delivery is typically provided by production tubing.While a well may have a monodiameter architecture, it may or may nothave a full bore production delivery system. Thus the assembly andmethods may include or exclude a fullbore production delivery system. Ifthe well has both characteristics of a monodiameter casing and monoboreproduction delivery system either extending to the formation barrier orthrough the producing formation, then the well design may be called a“MONOWELL”. A MONOWELL well has both monodiameter characteristics andfull delivery characteristics. Any combination of the differentembodiments between the monodiameter and fullbore production deliverysystem can made up a MONOWELL. “Monodiameter” means that the boreholeforming the wellbore has a substantially common diameter along itsentire length, i.e. from surface to either the reservoir barrier orbottom of the well. The monodiameter wellbore extends from the surfaceto at least the reservoir barrier and may extend to the bottom of thewellbore.

The assembly and methods of the present invention are equally applicableto land wells or offshore wells where the rig is land based or on anoffshore platform or vessel, respectively. Although the monodiameterwellbore may have any depth, such as 100 feet or more, the monodiameterwellbore is particularly advantageous in a deep well, such as a wellhaving a depth greater than 1000 meters. The assembly and methods may beused for producer and injector well architectures or any combinationthereof.

Preferably the monodiameter wellbore has a minimized architecture withat least one nominal casing string extending from the top of the well tothe top of the reservoir and may be constructed in sections or as oneunit. The casing may be chemical casing, expandable casing, includingmetallic, composites, fiberglass, or a combination thereof. Chemicalcasing and/or expandable casing permit the drilling of a large boreholediameter that extends across all of the non-producing formations andachieves a common inner casing extending the entire length of theborehole. This produces a monodiameter wellbore or borehole diameterwith a substantially monodiameter casing and replaces conventionalmultiple strings of concentric casing with different borehole diameters.

An assembly for constructing a monodiameter wellbore includes abottomhole assembly having an overgauge hole drilling member and/or anenergy balanced extended gauge bit drilling member, a directionalsteering assembly, a measurement while drilling tool, and a loggingwhile drilling tool; a work string attached to the bottomhole assemblyand extending to the surface; drilling fluids flowing through the workstring and bottomhole assembly; chemical casing disposed in theborehole; expandable casing disposed in the wellbore; and a sealingcomposition disposed between the expandable casing and the wellborewall.

A method for drilling a monodiameter borehole includes drilling aninitial portion of the borehole with a drilling assembly having a bit,downhole motor and reamer; applying a catalyst base material to theborehole wall during drilling; back reaming the borehole as the drillingassembly is raised through the initial borehole portion; applying a setup material to the borehole wall as the borehole is back reamed; forminga chemical casing by reacting the set up material with the catalystmaterial; repeating the above steps by drilling additional boreholeportions until the borehole is drilled; and installing a string ofcasing in the borehole.

A preferred method of forming the monodiameter wellbore includesdrilling a monodiameter borehole from the surface to the top of theproducing formation and applying a chemical casing to the borehole wall.Preferably the monodiameter wellbore is then cased with expandablecasing upon the completion of the drilling of the wellbore. It isadvantageous to drill one wellbore from the surface down to the top ofthe reservoir barrier with one casing string installed throughout thewellbore. In a second phase, the borehole is drilled across thereservoir using temporary sealing, under-balanced, over-balanced orspecial drilling fluids. Alternatively, sections of the borehole formingthe wellbore may be cased with expandable casing after each boreholesection has been drilled thereby maintaining a monodiameter casing.

The present invention achieves design optimization and efficiencies byreducing borehole size utilizing expandable casing and/or chemicalcasing. The use of expandable casing and/or chemical casing reduces thenumber and size of casing strings thereby reducing the materialsrequired to drill and complete a monodiameter well. Also the number andsize of high pressure risers may be reduced in a deep water well.Expandable casing also permits cladding or sealing, and chemical casingpermits the use of sealants. The expandable casing allows theconsolidation of conventional casings strings and operations. Byutilizing expandable casing, additional borehole size is not reducedwhich otherwise would be required for casing hangers, annular spacingbetween casing strings, and float shoes. Still further, the cladding ofthe adjacent sections of expandable casing eliminates large bulky linerhangers, which otherwise require additional borehole diameterutilization. Expandable liner hangers can be utilized. The monodiameterwell architecture, however, will not require the liner to have a largerdiameter supporting. Of course, larger diameter casing requires not onlya greater amount of drilling fluid to drill the borehole but also alarger amount of cement to cement the casing in the borehole.

The MONOWELL architecture has several unique features and advantagesover the traditional well construction architecture. The methods andapparatus of the present invention form a monodiameter wellbore in thewell reducing overall borehole dimensions. Thus the MONOWELL minimizesfluid requirements and volumes, equipment size/volumes, and materialsrequired in the hydrocarbon, gas, water businesses, and/or any otherdrilling and production business. It utilizes less drilling fluids andcement. The drilling fluids and cement required for the well are reducedbecause large diameter boreholes and large diameter casing are notrequired. These are particularly advantageous in deep water wells whereequipment size and fluid volumes must be optimized due to high cost. Itreduces the amount of earth cut and thus reduces the cuttings generated.It has less environmental impact than a conventional wellbore byreducing the materials utilized, the earth contacted, the materialsdisposed, and the energy consumed during the well construction process.

Reducing the materials provides many advantages. Less drilling fluid andcement are required, drilling time is reduced, and smaller fluid volumeand horsepower capacity rigs may be used. Still further, bulk storage onlocation is eliminated and horse power requirements are substantiallyreduced.

In reducing overall borehole dimensions, conventional casings, linersand tubing, as well as risers in subsea wells, are reduced in size orare eliminated. The monodiameter casing eliminates the series of nesteddifferent diameter casings. In a subsea well, instead of having a 36inch conductor casing, the conductor casing may be 17 to 18 inches. Thedrilling blowout preventer is reduced from the standard 18¾ inch BOP toa 13⅝ inch BOP. The diameter of the riser extending from the ocean floorto the surface is also reduced. The number and size of surface andintermediate casings and high pressure risers may be reduced in a deepwater well. The size of the hangers are reduced. It utilizes a smallerwellhead, casing, and risers for the final reservoir penetration.

MONOWELL architecture also allows the reduction in equipment sizepermitting the use of a small drilling rig, workover rig, or wellintervention device. The methods and apparatus of the present inventionallow the use such that a smaller, less sophisticated offshore rig, suchas a second or third generation rig, may be used to drill the wellrather than a fifth or sixth generation rig that handles largerboreholes and casing in the case of deepwater operations. Smaller landrigs may also be used particularly in horizontal and long extended reachwells.

Other objects and advantages of the invention will appear from thefollowing description.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of a preferred monodiameter embodiments ofthe invention, reference will now be made to the accompanying drawingswherein:

FIG. 1 is a schematic view of a conventional deepwater well;

FIG. 2 is a schematic elevation view of a prior art bell end systemusing expandable casing;

FIG. 3 is a schematic elevation view of both the non-producing boreholeand producing borehole having been drilled and cased with productiontubing installed;

FIG. 4 is a schematic of the drift diameter for a bit and drill collarin a straight borehole;

FIG. 5 is a schematic of the drift diameter for a bit and drill collarin a spiraling borehole;

FIG. 6 is a schematic of a MONOWELL bottomhole assembly;

FIG. 7 is a schematic of a MONOWELL illustrating chemical solutions forthe wellbore;

FIG. 8 is a schematic of lengths of casing being extended through thechemical solutions shown in FIG. 7;

FIG. 9A is a schematic elevation view of an initial section ofnon-producing borehole for a monodiameter wellbore being drilling with aslickbore bit;

FIG. 9B is a schematic elevation view of the borehole section of FIG. 9Awith a near bit reamer enlarging the borehole section;

FIG. 9C is a schematic elevation view of the borehole section of FIG. 9Bcased with chemical casing;

FIG. 9D is a schematic elevation view of another section ofnon-producing borehole for a monodiameter wellbore being drilling with aslickbore bit;

FIG. 9E is a schematic elevation view of the another borehole section ofFIG. 9D with a near bit reamer enlarging the another borehole section;

FIG. 9F is a schematic elevation view of the non-producing borehole forthe monodiameter wellbore of FIGS. 9A-E after have been drilled, backreamed and chemical casing applied;

FIG. 9G is a schematic elevation view of the non-producing borehole forthe monodiameter wellbore of FIG. 9F with metal casing installed;

FIG. 10 is an elevation view, partly in cross section of a slickboresystem;

FIG. 11 is an elevation view partly in cross section of a slickboresystem with a rotary drilling assembly;

FIG. 12 is a schematic elevation view of a non-producing borehole beingdrilled with a standard bit and the chemical casing mixed with thedrilling mud;

FIG. 13A is a schematic elevation view of an initial section ofnon-producing borehole for a monodiameter wellbore having been drilledand an initial section of expandable casing installed in the boreholewith no chemical casing;

FIG. 13B is a schematic elevation view of another section ofnon-producing borehole for a monodiameter wellbore having been drilledand with a next section of expandable casing in the unexpanded positiondisposed within another borehole section;

FIG. 13C is a schematic elevation view of the another section ofexpandable casing expanded and cladded to the initial section ofexpandable casing;

FIG. 13D is an enlarged view of the overlapped portion of the adjacentsections of expandable casing of FIG. 13C;

FIG. 13E is a schematic elevation view of the non-producing borehole forthe monodiameter wellbore with a plurality of sections of expandablecasing installed;

FIG. 14 is a schematic elevation view of a monodiameter wellbore havingboth chemical casing and expandable casing;

FIG. 15 is a schematic elevation view of a monodiameter wellborecombined with a structural casing;

FIG. 16 is a schematic of a MONOWELL completion with tubing in the upperborehole having the same inner diameter as the liner extending throughthe reservoir;

FIG. 17 is a schematic of a MONOWELL with nested expandables in theupper bore having mechanical solutions and an expandable liner hangerand with a gas tight expandable liner and expandable screens extendingthrough the reservoir;

FIG. 18 is a schematic of a MONOWELL having a 7 inch monodiameter casingand a 4.5 to 5.5 monobore full production delivery system usingmechanical and fluid technologies;

FIG. 19A is a schematic of a monodiameter multi-lateral well;

FIG. 19B is a schematic of a monodiameter side-tracked well.

FIG. 20 is a schematic elevation view of a monodiameter wellbore havingboth chemical casing and expandable casing extending through the entirewellbore for a water well;

FIG. 21 is a schematic elevation view of a monodiameter wellbore beingdrilled with composite coiled tubing by a bottom hole assembly with apropulsion system;

FIG. 22 is a schematic of a wired composite drilling unit for reservoirdrilling and completion; and

FIG. 22A is a cross-section through the wired composite coiled tubingshowing conductors embedded in the wall of the composite tubing.

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and will herein be described in detail. Itshould be understood, however, that the drawings and detaileddescription thereof are not intended to limit the invention to theparticular form disclosed, but on the contrary, the intention is tocover all modifications, equivalents and alternatives falling within thespirit and scope of the present invention as defined by the appendedclaims.

DESCRIPTION OF PREFERRED EMBODIMENTS

The assembly and methods of the present invention construct a MONOWELL(a coined term) having a monodiameter and monobore. The monodiameter isa monodiameter casing disposed in a monodiameter wellbore havingdiametric efficiency. The monobore is a nominal fullbore productiondelivery system. A MONOWELL extends from the surface to at least thereservoir barrier and may extend to the bottom of the wellbore.

A monodiameter casing is a casing which has a substantially consistentouter nominal diameter, e.g., whose outer diameter varies less than anominal three inches and preferably less than one inch, from the surfaceto the formation barrier. The monodiameter casing may be expandablecasing and/or chemical casing.

A monobore is a nominal fullbore production delivery system, such as aproduction tubular, which either extends through the monodiameter casingfrom the tubing hanger to the formation barrier or extends through themonodiameter casing from the surface and through the producingformation. In a preferred case, the monobore extends from the tubinghanger down through the producing formation. A full bore productiondelivery system includes a tubular string or continuous tubing, togetherwith all production components in the string or tubing, having a fullproduction bore, i.e., the same nominal internal diameter throughout theconduit no matter whether the well is an injection well or producingwell. There are no neck downs in the production conduit and allproduction components in the production conduit are full bore includingdownhole safety valves, nipples, and pressure/temperature gauges, forexample. While a well may have a monodiameter architecture, it may ormay not have a full bore production delivery system. Thus the assemblyand methods of the present invention may include or exclude a fullboreproduction delivery system. For example, hydrocarbons may be producedthrough the production casing and liner where the production casing andliner are protected from corrosion such as by a corrosion inhibitorcoating.

If the well has both the characteristics of a monodiameter casing and amonobore production delivery system either extending to the formationbarrier or through the producing formation, then the well design may becalled a “MONOWELL”. A MONOWELL well has both monodiametercharacteristics and full delivery characteristics. Any combination ofthe different embodiments between the monodiameter and fullboreproduction delivery system can made up a MONOWELL.

If the well has all the characteristics as described above for themonodiameter architecture from the reservoir barrier to surface, plus ata minimum, a common uniform nominal inner diameter conduit from thereservoir barrier to the surface, normally called tubing and associatedcompletion equipment such as safety valves, and etc. Then the well is aMONOWELL.

“Monodiameter” means a substantially common diameter. For example, a“monodiameter casing” is a casing having a substantially common nominalouter diameter along its entire length. Preferably the monodiametercasing also has a substantially common nominal inner diameter along itsentire length, although not required. A “monodiameter wellbore” is aborehole forming the wellbore having a substantially common diameteralong its entire length. The monodiameter wellbore extends from thesurface to at least the reservoir barrier and may extend to the bottomof the wellbore. Although the monodiameter wellbore may have any depth,such as 100 feet or more, the monodiameter wellbore is particularlyadvantageous in a deep well, such as a well having a depth greater than1000 meters.

The present invention relates to methods and apparatus for drilling amonodiameter wellbore for receiving a monodiameter casing which in turnmay receive a monobore production delivery system in constructing aMONOWELL. A MONOWELL may or may not have a monodiameter borehole whichwill depend upon the formation.

The present invention will be described for use in the oil and gasexploration and development business. The invention, however, can beapplied to any and all penetrations in the earth including the miningindustry, water industry, and other industries that involve drilling aborehole.

The present invention is also directed to simple and complex wellstructures including multi-lateral, concentric or multi-formation,complex or artificial lift wells where fluids may be injected and/orproduced at the same time all within the same wellbore. The injectionmay occur down through the flowbore of the work string and productionthen passes up the annulus or in the reverse.

There are shown specific embodiments of the present invention with theunderstanding that the present disclosure is to be considered anexemplification of the principles of the invention, and is not intendedto limit the invention to that illustrated and described herein. Variousdimensions, sizes, quantities, volumes, rates, and other numericalparameters and numbers have been used for purposes of illustration andexemplification of the principles of the invention, and is not intendedto limit the invention to the numerical parameters and numbersillustrated, described or otherwise stated herein.

In particular, various embodiments of the present invention provide anumber of different constructions, apparatus and methods of drilling,casing, and completing a MONOWELL, each of which may be used to drill,case, and complete a MONOWELL for a land or subsea well including a newborehole, a vertical borehole, a straight borehole, an extended reachborehole, extending an existing borehole, a sidetracked borehole, ahorizontal well, a deviated borehole, a multi-lateral borehole, andother types of boreholes for drilling and completing one or moreproduction zones. Further the present invention relates to bothproducing wells and injection wells. Still further, the presentinvention relates not only to new wells but to existing wells. Theembodiments of the present invention also provide a plurality of methodsfor drilling, casing, and completing a monodiameter wellbore. All theabove is applicable to the MONOWELL architecture as well. In othercases, in general, it means, full conduit delivery means from thereservoir (producing formation) to the wellhead.

The monodiameter can apply to all multi-laterals including the primarywellbore or individual lateral wellbores. The monobore can apply abovethe junction of the laterals, i.e., the fullbore delivery system havingan inner conduit with a fullbore diameter extending above the joining ofthe laterals. The laterals may or may not be expandable casing orscreens and may have a diameter equal to or less than the monodiametercasing.

The different teachings of the embodiments discussed below may beemployed separately or in any suitable combination to produce desiredresults.

The following definitions will be followed in the specification. As usedherein, the term “enlarged wellbore” refers to a wellbore or boreholehaving a diameter greater than that of the internal diameter of thepreceding casing or liner, preferably greater than the external diameterof the preceding casing or liner, such a wellbore being provided ordrilled in a manner known to those skilled in the art, as described morefully hereinafter. As used herein, the term “work string or drillstring” is understood to include a string of tubular members, such ascasing, tubing, jointed drill pipe, metal coiled tubing, compositecoiled tubing, drill collars, subs and other drill or tool members,extending between the surface and on the lower end of the work string, atool normally utilized in wellbore operations. A work string or drillstring may be used for drilling and be a drill string or installationmeans. It should be appreciated that the work or drill string may bemade of steel, a steel alloy, a composite, fiberglass, or other suitablematerial. As will be understood by those skilled in the art, a “casing”is a string of tubulars extending from the surface down into thewellbore and a “liner” is a string of tubulars extending from the lowerend of a casing string and down into the wellbore. Liners may bedisposed within casing. Casing and liners are typically composed of pipesegments or sections assembled and coupled by suitable means, such as bythreading. “Casing” may be used generically and also include liners.Reference to up or down will be made for purposes of description withthe terms “above”, “up”, “upward”, or “upper” meaning away from thebottom of the wellbore and “below”, “down”, “downward”, or “lower”meaning toward the bottom of the wellbore. An “upper borehole”,“non-producing borehole or wellbore” or a “non-producing formation” isdefined as any formation above the “lower borehole”, “producing boreholeor wellbore”, “producing zone”, “reservoir” or “producing formation,”i.e., the target formation with the desired production or injection zoneor reservoir. Some non-producing formations may be hydrocarbon bearing.The desired production zone is sometimes referred to as the target zonefor producing either oil, gas or water, or for injecting water, steam,gas, carbon dioxide or other fluids. “Geo-mechanical forces” are forceson the formations, such as compaction forces, seismic forces, tectonicforces, or other forces relating to borehole stability.

A trip into the well may be defined as the operation of lowering orrunning a tool into the well on a work string. A trip includes loweringand retrieving the tool on the work/drill string. In a drillingoperation, the tool will include a bit, typically part of a bottom holeassembly (BHA).

In the description which follows, like parts are marked throughout thespecification and drawings with the same reference numerals,respectively. The drawing figures are not necessarily to scale. Certainfeatures of the invention may be shown in exaggerated scale or inschematic form and some details of conventional elements may not beshown in the interest of clarity and conciseness.

Referring initially to FIG. 3, there is shown schematically a MONOWELL12 with a monodiameter wellbore 10 extending from the surface 14 to thebottom 15 of the well 12 within producing reservoir 30. Monodiameterwellbore 10 includes at least a monodiameter borehole 10A extending fromthe surface 14 to the top of the reservoir, i.e. reservoir barrier 16,hereinafter referred to as the “upper borehole”, “non-producing boreholeor wellbore” or “non-producing formation”, and a borehole 10B extendingacross or through the reservoir 30 from the reservoir barrier 16 to thebottom of the well 15, hereinafter referred to as the “lower borehole”,“producing borehole or wellbore”, “producing formation”, or “reservoir”.Producing wellbore 10B may or may not be a part of the monodiameterwellbore 10. It should be appreciated that the non-producing wellboremay extend across a secondary producing zone as distinguished from theconventional producing wellbore which extends across the targetproducing zone. A monodiameter wellbore is a single borehole extendingfrom the surface to at least the reservoir barrier and may extend to thetarget depth of the well. The monodiameter borehole forming the wellbore10 has a substantially common nominal diameter along its entire length,i.e. from surface 14 to top of the reservoir barrier 16, asdistinguished from the conventional plurality of boreholes havingdifferent diameters as shown in prior art FIG. 1. The monodiameterwellbore 10 may or may not extend to the target depth of the well.Although the monodiameter wellbore 10 may have any depth, such as 100feet or more, the monodiameter wellbore 10 is preferably for a deep wellsuch as a well having a depth greater than 1000 meters from surface 14to bottom 15. It should be appreciated that the monodiameter wellbore 10will have a predetermined outer diameter 18 as set forth in the well andengineering plan. A monodiameter is just one borehole extending from thetop to the bottom of the well. A higher level of engineering andtechnological precision is needed to deliver the monodiameter wellarchitecture compared to traditional well construction processes. When amonodiameter is drilled, increased precision and attention is applied.

The monodiameter non-producing wellbore 10A is cased to form amonodiameter casing extending from the top to the bottom of the well.Although casing 70 may be conventional casing extending from the surface14 to the reservoir barrier 16, it is most preferred for the casing tobe expandable casing. Once the casing is in place, it is then cementedinto upper wellbore 10A by flowing cement 72 into the annulus 74 formedbetween casing 70 and wellbore wall 44. Although a metal casing ispreferred for casing 70, it should be appreciated that casing 70 may bemade of a composite, or fiberglass or other non-metal material. Further,it should be appreciated that the casing may be chemical casing,hereinafter described, or a combination of the above.

The outer diameter of the casing 70 has a substantially common dimensionfrom surface 14 to the formation barrier 16. The casing 70 has asubstantially consistent nominal outer diameter along its entire length,not varying over three inches and preferably not varying over one inch.Although it is preferred that casing 70 have a consistent inner diameterfrom surface 14 to the formation barrier 16, casing 70 does not have tohave a consistent inner diameter. The set of casings 70 preferably havea smaller diameter which extends from the surface 14 to the formationbarrier 16 which is smaller than that of the series of conventionalcasings. If the production tubular passing through the producingformation has the same inside diameter as the completion tubular 80extending from the formation barrier 16 to the surface 14, then it is amonobore. Normally a liner 17 is set near the bottom of the completiontubular 80. The completion tubular 80 is preferably stung into the linerand expansion cladding can occur for them to form a conduit or the linercan be hung off using a liner hanger, preferably an expandable linerhanger.

One objective is to reduce the overall diameter of the wellbore and itis preferred not to drill a borehole diameter any greater thannecessary. The larger the diameter of the borehole, the larger therequired drilling equipment, the larger the rig, and the more powerrequired to drill the borehole. A larger diameter borehole also requiresa larger casing. Further, there is more earth to move in a largerdiameter borehole and more cement is required to fill the largerannulus. Another reason for maintaining a small borehole diameter is toreduce the volume of fluids required to complete the well. This includesdrilling fluids as well as cement. Thus, the entire operation for alarger diameter borehole becomes more costly.

Referring now to FIGS. 4 and 5, there is shown in FIG. 4, a straightborehole 21 drilled by a bit 23 having a diameter D_(bit) supported by adrill string having a drill collar 25 with a diameter D_(DC). Thereduced wellbore pass-through area or “drift” has a diameter D_(Drift).The formula for calculating drift diameter is bit diameter+drill collardiameter divided by 2. For example, in a hole drilled with a 12¼ inchbit and an 8 inch drill collar, the largest diameter tubular that couldbe guaranteed to run through this wellbore would be 10⅛ inches. FIG. 5illustrates the drift diameter of a spiral wellbore 27. The pass-througharea or drift is shown by the dotted lines between the arrows. Thus itis apparent that spiraling is undesirable since it reduces the driftdiameter.

The casing must extend through the drift diameter. The gap or clearancebetween the outer diameter of the expandable casing and the innerdiameter of the borehole wall preferably is one inch and may be as greatas 3 or 4 inches. This gap or clearance is required for the cementingoperation, preferably a one inch clearance. With these smallerclearances, the borehole can not be a spiral. In using conventionalcasing, the clearance may be anywhere from approximately 6 to 10 inches.A wash out for conventional casing, for example, may be anywhere from 6to 36 inches or greater.

The preferred borehole has a diameter which is the minimum required toinstall the desired sized casing. This of course minimizes the clearancebetween the casing and the borehole wall, i.e. the annulus. Therefore,to install a monodiameter casing, the wellbore must be a qualityborehole. Another objective is to achieve an open borehole which willallow the use of a monodiameter casing such as expandable casing, i.e.,the wellbore has a diametric efficiency which will receive and cement amonodiameter casing and allow the use of expandable casing. Thus the newwell concepts, as described for the installation of expandable casing,will require narrow annuli, such as annuli up to approximately 3 to 4inches on diameter.

A quality borehole is required to achieve the MONOWELL. A high-qualitywellbore is generally considered to have (1) a gauge hole, (2) a smoothwellbore, and (3) a wellbore with minimum tortuosity. Spiraling is theprimary contributor to poor borehole quality and almost every wellcontains some degree of spiraling unless specific actions are taken toprevent it. A diametric efficient borehole includes the qualities of ahigh quality borehole and preferably includes a smooth cylindricalborehole wall, a borehole diameter which is only slightly greater thanthe outer diameter of the expandable casing, and a straight borehole. Astraight borehole means no tortuosity in the borehole, i.e., nospiraling of the borehole. Conventionally, the torque on the drillingassembly causes a reverse spiral in the direction of drilling wherebythe drilling assembly drills a spiral borehole. The spiraling boreholecan sometimes reduce or increase the diameter of the borehole throughwhich the casing can pass. Thus, spiraling must be minimized.

Tortuosity occurs when a well deviates from a straight hole.“Micro-tortuosity” is where the hole axis is a spiral instead of astraight line, i.e., the borehole has a spiral pitch. Friction factorsand tortuosity index may be used to quantify the effect of tortuosity onthe torque and drag. Although an MWD tool routinely records theinclination and direction of the wellbore, typically the MWD tool is 30feet long and therefore can not detect a tight spiral because the MWDtool spans several pitches of spiral and cancels them out. The MWD toolcan not detect hole spiral because it measures the inclination anddirection of the drift, not of the wellbore itself. Micro-tortuosity isdefined as small scale borehole spiraling where the hole axis becomes ahelix instead of a straight line. The only way micro-tortuosity can bedetected is by advanced wireline survey techniques, MWD acoustic calibertools, or by the interpretation of back calculated friction factors.

For example, in a conventional well, a 12¼ inch borehole willaccommodate a 9⅝ inch casing. The 9⅝ inch casing will receive an 8½ inchbit for installing a 7 inch casing. The 7 inch casing will receive a 6½inch bit. If the wellbore had diametric efficiency, the 12¼ inch casingwould accommodate a 10¾ inch casing. The 10¾ inch casing would receive a9½ inch bit for installing an 8¾ inch casing. The 8¾ inch casing wouldreceive a 7½ inch bit. Thus the diametric efficient wellbore increasesthe diameter of the wellbore by at least an inch.

It is preferred that the casing OD be very close to the borehole ID. Thereason for the close tolerance between the borehole wall and casing isbecause of the expandable casing. Expandable casing requires a betterprecision borehole than conventional casing. The expandable casing withappropriate expandable casing cement, forms a unique sealing and supportsystem. The borehole wall also serves as partial support for theexpandable casing.

It is more critical that the expandable casing be sealed with theborehole wall than in a conventional installation. For example, ifexpandable casing is installed, and a portion of the expandable casingis not sealed with the borehole wall, then it becomes necessary toinstall an additional expandable casing or use extra sealant materialsto fill voids in the unsealed portion.

The failure to have proper seal and support of the cement is aggravatedwhen expandable casing is used. The problem is caused by the fact thatthe expandable casing is expanded outward toward the borehole wallunsupported. The cementing operation occurs before the expandable casingis expanded. In the expansion of the expandable casing, the cement iscompressed. The cement for expandable casing does not set until afterthe expandable casing is expanded. The expandable casing cement takeslonger to set and may include a retardant to delay the setting time. Theexpandable casing must be expanded into the cement so as to create andestablish a seal with the borehole wall. If the expandable casing is notproperly sealed, then there may be channeling which will allow differentformations to communicate which is against regulations or instability ofthe casing.

If a large borehole is drilled, then large wash outs may be caused inthe borehole wall. That portion of the expandable casing adjacent to thewash outs will not be sealed at the borehole wall. If the borehole has awash out, and the expandable casing is not properly sealed or supported,then the MONOWELL may have a shorter life.

A special cement is required to avoid a micro fracture. The cement forexpandable casing is more of a sealant than it is a conventional cementfor conventional casing. The expandable casing cement has got a silicantin it.

Diametric efficiency is the maintenance of the optimum hole size throughto the reservoir regardless of other well construction requirements orconstraints. Expandable solutions that maintain or improve diametricefficiency in a range of applications from multilaterals, horizontals,extended reach, high pressure high temperature (HPHT), and deepwaterenvironments will encourage the use expandables. The maintenance ofdiametric efficiency through the use of expandable casing is asignificant step towards the MONOWELL. To achieve a diametric efficientborehole, components for drilling the borehole must be optimizedincluding the type of wellbore delivered by the bit, the directionaltools, the drilling fluids, casing, expandable casing sealingcomposition, formation sealing methods, among others.

A higher level of engineering and technological precision are needed todeliver the monodiameter well architecture compared to traditional wellconstruction processes. When a monodiameter upper borehole is drilled,increased precision and attention is to be applied to the followingareas: a clear understanding of the formation to be drilled and beingdrilled; borehole stability; drilling hydraulics; effective managementof equivalent circulating density (ECD); borehole quality; method ofstrengthening the borehole (borehole management); well-life integrity;reliability and run life of the bottomhole assembly with bottomholeassembly components; longer cementing and casing execution intervals;borehole structural support; and the life, i.e., time element, of theopen borehole. See SPE 77628: “Well Construction Efficiency ProcessesYielding a Significant Step Change” by Wylie, Zamora, Terry, and Muralito be presented at the SPE Annual Technical Conference and Exhibition onSep. 29, 2002 to Oct. 2, 2002.

The common inner diameter or width, i.e., monobore, will extend acrossthe reservoir in most MONOWELLs. If this is the case, increasedengineering precision compared to traditional well completionengineering will be applied in the following areas: completion,beginning with drilling of the reservoir barrier; borehole quality;borehole stability across the reservoir; reservoir evaluation; reservoirproductivity; and formation damage minimization.

To be successful, the monodiameter wellbore and MONOWELL require ahigher level of precision in all areas including seismic interpretation,reservoir modeling, planned well path, and individual drilling componentdesigns. Historical information from drilling the surrounding wells,along with seismic and geomechanical analyses, provides valuable insightinto the well path and borehole stability management. In explorationareas, this information is limited, but similar formation informationcan be used as well as real-time information.

Well planning is conducted in the selection of the apparatus and methodsof the present invention required for constructing a monodiameterwellbore at a particular location. Components may be included asconditions warrant. Greater well planning is preferred for amonodiameter wellbore to avoid geological incidents and/or engineeringmistakes. In a conventional well, if a geological incident occurs,another string of casing is installed into the well. In a monodiameterwellbore, the wellbore already has been reduced so that there is minimalspace in the annulus to correct any geological or mechanical incidents.Mistakes may cause a reduction in the planned diameter for the well.Another expandable may be inserted and expanded inside an existingmonodiameter casing. Another type of mistake includes drilling mistakes.Thus, advance well planning and engineering is important to avoidgeological incidents or engineering mistakes. It is not necessary thatall of the analyses described below be made for the well planning andengineering but should be investigated and considered for each well.

Various information is needed in planning and constructing amonodiameter wellbore. Seismic analyses is useful in determiningpotential formation depths and breaks. Geomechanical analyses isutilized to determine potential borehole stability issues from allformations throughout the wellbore. It is also useful in drilling fluidformulations, drilling bit designs, well path trajectories, andcompletion design for extending the well's life. It is further useful indetermining potential tectonic stresses, potential compaction andpossible shallow water flows. Geomechanical models and analysis areavailable, such as from Baroid, Geomechanics International, Sperry Sun,and Landmark, which take into account both chemical and mechanicalborehole stability issues and can analyze the borehole stability from amechanical standpoint. Tools are in the development stages which candetermine seismic and borehole stability ahead of the bit. Geologicalanalyses, logging and seismic are utilized to determine what type offormation structure, pressures, and lithology make-ups are present. Thisallows one to formulate the sealants, chemical casing, settable spots,cements and drilling mud compositions, and fluid volumes to hold backthe formation(s).

Loading and growth of casing during well life is considered in themonodiameter wellbore engineering plan. This includes detailed loadingand growth analyses which take into account the reduced tolerance,reduced spacing, and dependence of one casing section upon anothercasing string in a monodiameter well architecture.

The reduced diameter of the monodiameter wellbore requires thatincreased attention be placed on casing wear considerations,particularly in the expandable casing scenario where the pipe has beenplaced in cold work form upon installation and expansion in thewellbore.

Hydraulics analyses is required for bits, drilling fluids and cementing.It is critical to determine the correct flow rates to determine bitcooling, cutting transport, as for example, as inaccurate results willlead to stuck pipe or a well control situation with a resulting re-drillor sidetrack. Various computer programs, such as from Security DBS,Sperry Sun, Baroid and Landmark, provide cementing analysis from theviewpoints of placement, hydraulics, and composition.

A monodiameter well can be constructed by placing nested expandables inthe same casing intervals where conventional casing would have been set.An improvement is to reduce as many casing intervals as possible andplace the well accurately across the reservoir. This action requiresreal-time information. Integrating the efficiency improvements in thewell-construction process can result in a large efficiency step change.

In many respects, well design is largely dictated by pore pressure andfracture pressure information. To extend hole intervals and optimizeplacement, real-time operations that involve collecting, analyzing, andinterpreting data should be available. Visualization models can helpinterpretation. Real-time information that updates the seismic,reservoir, geomechanical, and drilling models (including 3D and 4Dvisualization models) allow updates and directives to be given to thebottomhole assembly so that immediate drilling actions can be taken.

Means, such as Landmark Graphic's 3D Drill View and 3D DRILL VIEW KM(Knowledge Management), allow the operator to visualize, analyze andinterpret MWD/LWD and drilling operational data in real-time. The 3Dvisualization of real-time data, together with the pre-planned earthmodel, enables the operator to make more rapid decisions. The 3D DrillView has the capability to display and manipulate (rotate, translate,zoom) geoscience earth model data objects together with drillingengineering and operations data for integrated knowledge management andreal-time decision making and offers integration and collaborationbetween drilling rig and operator with the capability for each site tovisually manage data and improve decisions for the entire operation.

The well-construction process becomes more efficient and long-term wellproductivity is improved by accurate placement of the well andcompletion design. For example, the following help extend holeintervals: (1) real-time feedback on actual vs. predicted pore pressureand fracture gradient, (2) real-time methods to influence or manage porepressure or fracture gradient, and (3) real time downhole drilling fluidrheology, viscosity and physical condition including percent of solids.

Real-time pore-pressure prediction and mechanical properties forfracture gradient and borehole stability can be used to adjust the mudsystem, cement formulations, or other specialty fluids for enhancing themechanical strength of the formation while drilling. Also, pore pressureand fracture gradient information can be used in mechanical casinginterval placement decisions. The real-time information might dictateshorter or longer intervals than planned. However, the primary aim is tolengthen actual cut intervals for as long as possible. Real-timetime-lapse resistivity can show permeable zones in the upper boreholethat might cause borehole stability issues. Across the reservoir, theinformation can help in designing the optimum completion design for bothshort and long term.

Drilling long, openhole sections with the potential for increasedopenhole exposure requires many considerations. The mud system must bechosen with consideration to penetration rate and borehole cleaning inaddition to the previous discussed borehole stability. Chemicalsolutions and techniques help extend casing setting lengths. Usingexpandable tubulars as the mechanical support in combination withchemical solutions can result in fewer multi-diameter “nesting”sections. The use of chemical solutions with non-expanded casing canincrease the length of traditional casing lengths that can be run aswell.

It is preferred that equipment and principles, such as those previouslydescribed, be used such that the well construction process is rapid andnot delay any operational changes as the well is drilled. Thus, there isa need for real time data collection and analyses. The data collected atthe bit is networked and integrated at the rig for analyses employed byINSITE ANYWHERE. Real time operations are preferred but not essential. Agamma ray device is preferred and can be powered by a battery with thedata collected after the gamma ray device is retrieved from the well.However, some major efficiencies are lost when the data is retrievedafter the fact and one can experience well construction monodiameterdifficulties in the delayed information. See U.S. patent applicationSer. No. 60/209,488 filed Jun. 6, 2000 entitled Real Time Method forMaintaining Formation Stability and Monitoring Fluid-FormationInteraction, hereby incorporated herein by reference. The benefits ofreal time operations are noted in this application.

Well path trajectory is a detailed torque and drag analysis that isrequired to determine the well path needed for the monodiameter wellboreto reach target depth. The optimum well path can be designed usingStrata-steer, INSITE ANYWHERE, Resolution 3D, a directional drillingpackage, MWD measurement while drilling, and logging while drillingtools, which preferably includes a gamma assembly at a minimum. Lookahead of the bit devices can and should be included in the LWD toolswithin the BHA.

To achieve a quality borehole having diametric efficiency, themonodiameter wellbore should have minimal tortuosity. A continuousborehole wall is preferred with a constant diameter wellbore andtherefore an oversized or “crooked” borehole is undesirable. A boreholewith high tortuosity includes bends and curves that cause gaps andincreased borehole diameter along the borehole. Further, tortuositymakes it very difficult to achieve a good cementing job because bigwashouts in the borehole cause the cement to collect in the gaps. Also,it is difficult to achieve a good cement job if there is not a smoothwellbore wall such that a constant annular area around the casing isachieved. A poor cement job also reduces the longevity of the well.Thus, although the monodiameter wellbore may be achieved, a qualitycement job is important across the production interval to avoid a bigwashout, poor production, erosion and early water or gas breakthrough.

A resulting high borehole quality can provide the following monodiameterbenefits: less vibration; smoother borehole; and improved logging toolresponse. Less vibration provides longer drilling tool reliability,better bit life, better toolface control, better weight transfer, andbetter cutter engagement to the formation. A smoother borehole is easierto clean, less torque and drag occurs on the bottomhole assembly, casingis easier to install, and the chance of extending the longermonodiameter casing interval depths are greater. With an improvedlogging tool response, the tools have less chance of getting stuck whena clean “gun barrel” borehole is provided, and better logging data canbe collected.

Attributes of the monodiameter downhole assembly should include a highlevel of efficiency getting to the desired location; a high boreholequality; appropriate drilling hydraulics; and high reliability andextended tool life. The drilling hydraulics prevent big wash outs in theborehole.

Components are required to achieve a straight borehole which will allowa monodiameter casing preferably including expandable casing, chemicalcasing, bit and directional tools which will produce no tortuosity. Thebit and directional tool preferably includes a full drift bit and aGEO-PILOT (“point the bit”) directional system or SLICKBORE system. SeeU.S. Pat. No. 6,269,892; U.S. patent application Ser. No. 09/378,023,filed Aug. 21, 1999 entitled Improved Steerable Drilling System andMethod, now U.S. Pat. No. 6,581,699; and U.S. patent application Ser.No. 10/230,709, filed Aug. 29, 2002 entitled Improved Steerable DrillingSystem and Method; all hereby incorporated herein by reference. See also“Halliburton New Technologies and General Capabilities” (5 pages). Thebit preferably has an extended gauge and may be energy balanced whichallows for equal volume cutting across the entire bit. An energybalanced bit is a bit where there is approximately the same loading oneach of the cutting elements of the bit. This allows the bit to wearevenly and not have to be prematurely replaced or pulled prior tocutting the entire interval. See U.S. Pat. Nos. 6,095,262; 6,213,225;6,401,839; and 6,412,577; all hereby incorporated herein by reference.

The best bit combination for drilling the monodiameter wellbore is anenergy-balanced SLICKBORE bit with a near bit reamer. The bit is energybalanced with all cutters being cutting equal loads—resulting in longerdrilling intervals. The near bit reamer in the drill string allows forenlarging/opening up of the wellbore, even to drill through cement floatequipment. The design of the SLICKBORE extended gauge bit allows for thebit and motor or rotary steerable device to act in concert allowing fora much smoother wellbore. Rotary steerable technology is disclosed inU.S. Pat. Nos. 5,685,379; 5,706,905; 5,803,185; and 5,875,859, allhereby incorporated herein by reference, and Great Britain references2,172,324; 2,172,325; and 2,307,533. U.S. patent application Ser. No.09/353,599 filed Jul. 14, 1999 entitled Steerable Rotary Drilling Deviceand Directional Drilling Method, now U.S. Pat. No. 6,244,361, herebyincorporated herein by reference.

Friction factors have been used to take into account several differentcomponents which increase torque and drag in the wellbore which in turncause spiraling. The most important factors are drilling fluid type andcomposition, total tortuosity, and formation type in the open holesection and casing condition in the cased hole section. The differencebetween the plan friction factors and the actual friction factors iscalled the tortuosity index. Wells drilled without spiraling have lowertorque and drag. The average open hole friction factors are reduced from0.27 to 0.21 in water-based mud, and from 0.12 to 0.1 in oil-based mud.Reduction of friction factors is believed to be the result of smootherwellbore.

The present invention reduces the tortuosity index, a measurement of howmuch tortuosity is in the wellbore, from 1.34 to 1.08. This suggeststhat absence of hole spiraling has a larger impact then the slide/rotateaction (large scale tortuosity) from the steerable motors. The datasuggests that spiraling is reduced by using extended gauge bits. Thetortuosity index for conventionally drilled wells is 1.34 while thetortuosity index of a SLICKBORE drilled well is 1.08. Thus, the presentinvention achieves diametric efficiency, in part, by maintaining thetortuosity index below at least 1.10. For a detailed discussion see SPE77617 entitled “Quantifying Tortuosities by Friction Factors in Torqueand Drag Model” by Tom Gaynor, Doug Hamer, and David C-K Chen, datedSep. 29-Oct. 2, 2002.

Spiraling may be minimized by using either a steerable motor drillingsystem or a rotary steerable drilling system. The steerable motordrilling system deploys the extended-gauge bits and has especiallydesigned mud motors with pin-down connections. The system is designed toeliminate spiraling. The extended-gauge bit prevents the bit from movingoff center. See OTC 14277 “Hole Quality: Gateway to Efficient Drilling,by David C-K. Chen, Tom Gaynor, and Blaine Comeaux, dated May 6-9, 2002.

Referring now to FIG. 6, there is shown a preferred bottomhole assembly210 including an extended gauge bit 212 with sensors, a GEO-PILOTsteerable “point the bit” rotary steerable system 214, a combo tool 216,a rock mechanics compression and slow shear sonic tool 218, a magneticresonance imaging tool 220, a near bit reamer 222, and a cutting removaldevice 224. The extended gauge bit 212 may be an energy balanced bit.The combo tool 216 may be a triple or quadruple combo tool. Thebottomhole assembly 210 is connected to a work string 226 which extendsto a second or third generation rig 228 or any land rig. A seismic orevaluation tool which investigates ahead of the bit may or may not beincluded.

The drilling systems for the monodiameter wellbore are preferablydirectional drilling systems that include devices that aid in drillingboreholes in accordance with the well plan. Such devices may or may notinclude, but are not limited to the real time point the bit rotarysystem 214 shown in FIG. 6, such devices as Halliburton's INSITEANYWHERE, Landmark's 3D DRILLVIEW and Halliburton's GEO-PILOT RotarySteerable System by Sperry Sun or other systems that assist in placingan accurate wellbore that provides a precise, real time wellboreplacement with a clean conditioned wellbore.

A near-bit reamer 222, which enlarges the borehole, placed above themeasurement while drilling/logging while drilling (MWD/LWD) tools canhold the bottomhole assembly 210 in the center of the borehole, causingequal cutting loading across the borehole. This centralization reducesoverall vibration, fatigue, and MWD/LWD failures. A near-bit reamer 222provides a lower bend in dogleg severity, resulting in reduced slidetimes. Also, the near-bit reamer design minimizes vibrations, whichresults in a better quality borehole and better logging results.

The near bit reamer 222 is preferred over the bi-center bit in drillingthe upper non-producing borehole. The near bit reamer permits drillingthrough the cement float shoe formed during the cementing operation ofthe previous installed casing. The near bit reamer can drill through thecement shoe and then continue on drilling the new borehole withouthaving to be stopped. The near bit reamer helps to build a smoothborehole allowing for a better completion. The near bit reamer can beused in applying a formation compatible fluid and may be useful inapplying chemical casing, cementing or improving the borehole quality ashereinafter described.

Although a near bit reamer 222 is shown in FIG. 6, various types ofpenetration members may be used to create the monodiameter wellbore 10.A particularly preferred bit is one that is energy balanced. However,any type of bit may be used with the present system. Depending on theformation, the following types of penetration members can be utilized indrilling a monodiameter well architecture: fixed cutter bits, rollercone bits, energy balance bits, anti-whirl three cone bits, holeopeners, near bit reamers, and bi-center bits. Most of these componentsare manufactured by Security DBS. Although these bits have certaindesign features that contribute to a better monodiameter wellbore,overgauge hole drilling is preferred. Bits utilized in drilling amonodiameter well, however, are not exclusive to these items.

It is preferred that the bit is “matched” to the directional steeringassembly. One such assembly is the SLICKBORE Drilling System, employedby Sperry Sun, having a matched mud motor and bit system, which enhancesdirectional control and improves hole quality. The SLICKBORE DrillingSystem includes an extended gauge bit, a downhole motor, and MWD and LWDtools, combined with a near bit reamer. Another system is the GEO-PILOTrotary steerable, point the bit, system 214 which includes a bit, arotary system, a downhole turbine, and MWD and LWD tools combined with anear bit reamer. A drilling efficiency package (ADT™ Applied DrillingTechnology Optimization Service) employed by Sperry Sun may be used witheither the SLICKBORE or Geopilot drilling systems. ADT is a suite oftools, software, and services designed to reduce trouble time andoptimize drilling practices by using critical data interpretation from avariety of downhole/surface sensors and specialized applications. TheADT adds sensors to the bottomhole assembly to provide real timemeasurements of various downhole parameters, such as hydraulics andborehole stability, which are transmitted to the operator or processorsat the surface. These measurements are analyzed and processed at thesurface and adjustments are then made to the drilling operatingparameters to optimize the drilling of the borehole. This optimizationallows the drilled borehole interval to be extended and for longborehole sections of various formations to be reliably drilled withoutchanging out the drill string. These bits are extended gauge whichreduces the flexing between the components and allows the bottom holeassembly components to act as one unit. An extended gauge bit or rotarysteerable extended gauge bit may be used. The GEO-PILOT rotarysteerable, point the bit, system 214 provides the most efficient meansof reaching the target location if the well is extended reach,horizontal, or over 16,000 feet, for example. ADT applies wellboreintegrity, hydraulics management, and drill string integrity to provideimproved drilling efficiencies. See “Halliburton New Technologies andGeneral Capabilities” (5 pages), hereby incorporated herein byreference.

Better borehole quality can be achieved by using a matched mud motorwith a pin-down connection and extended-gauge PDC bit, i.e., SLICKBORE.This arrangement reduces the bit to bend distance by shortening thebearing section. Better borehole quality can also be achieved bydirecting the bit with a deflection of a shaft. See the discussion rerotary steerable assemblies. The extended gauge PDC bit keeps the bitfrom wobbling on the end of the drill string and limits hole spiraling.The extended gauge-bit direction is controlled by deflection of a shaft.Therefore, bit loading is axial, allowing efficient concentric cuttingof the formation and leading to increased rate of penetration (ROP),increased bit life, and a regular hole geometry, which are criticalfactors in building a monodiameter well.

Reaching the desired location through the most efficient means is adesired attribute of the bottomhole assembly. Extending casing lengthsrequires the bottomhole assembly to drill longer and with moreprecision. Efficient concentric cutting of the formation, increased bitlife, and a smooth hole geometry are qualities needed in a monodiameterborehole. The system is directed by comparing actual data to therequirements of the well plan through the real-time system that readsinformation from the lithology and inclination sensors at the bit. Thismethod allows immediate changes in direction to be made to the steerablesystem rather than delayed corrections. Real-time information, alongwith the right directional tools, provides the most efficient way to getto the target location with the smoothest borehole.

Due to the narrow monodiameter wellbore and the various formationsdrilled, various tools may be used with the bottom hole assembly duringdrilling to detect the different formations through which the boreholewill pass. For example, special MWD (Measurement While Drilling) and LWD(Logging While Drilling) equipment may be used to be run while drillingthe well. This helps in monitoring fracture gradients, boreholestability issues, and stuck pipe issues. Formation conditions can changequickly and may not be expected. Other formation evaluation toolsinclude, but are not limited to, pressure while drilling devices (PWD),such as those employed by Sperry Sun, to identify formation conditions,flow connection devices for detecting wellbore breathing, and bi-modalacoustic tool (BAT) employed by Sperry Sun, ahead of the bit and seismictools. See U.S. Pat. Nos. 5,886,303; 5,899,958; 6,026,913; 6,102,152;6,131,694; 6,151,554; 6,196,335; 6,478,107; and 6,400,646, all herebyincorporated herein by reference. It also includes LWD tools that helpto collect data for doing geomechanical analyses at the bit and beforethe bit. The formation evaluation tools and the real time geomechanicalanalyses may indicate that a higher or lower weight mud system be usedfor a particular formation. The drilling mud, cement, chemical casing orexpandable casing are then modified for the detected formations.

Borehole hydraulics are considered in the design of the bottomholeassembly. Potentially, the MONOWELL's upper borehole can be drilled withonly one full trip because the drilling interval can be extended to thelength of the well. Cutting beds can build up, causing possible troublespots or a stuck bottomhole assembly. In-line turbulators (cuttings-bedimpellers) 224 that disturb cuttings beds may be included in the drillstring to help clean out the wellbore, particularly in the tangentsections (if drilling a directional hole). The cuttings bed impellerprevents build up and facilitates cuttings bed removal, reducing stuckpipe situations and drill string torque. The present embodiments are notlimited to any particular well tools. For example, the well tools arenot be limited to a MWD and LWD tool. Any MWD or LWD tools may be used.

Finally, reliability and run life of the bottomhole assembly can beextended by modeling and measuring vibration, pressure, and lithologyfrom downhole, and reporting them to the surface. Adjustments can thenbe made at the surface to accommodate occurrences downhole. Theseadjustments can result in a longer run life for the bottomhole assembly.

In the traditional well, the wellbore may be open 3 to 5 days beforestability of the borehole wall becomes a problem. After that portionsmay start to fall into the borehole. In the present invention, longerintervals are going to be drilled thus leaving the borehole open forlonger than 3 to 5 days. Thus there is an extended time in which theborehole wall is unsupported by casing during drilling. Thus, theborehole wall must remain stable for a longer period of time than inconventional drilling. This longer time element is due to drillinglonger intervals. To achieve this, the drilling fluid system must beworking properly. The bit and directional tools must be matched and inalignment.

More open hole is left open and for longer periods than in conventionaldrilling thus allowing greater time for reactions between the drillingfluids, formation fluids and formation lithology to occur. One can nothave aggressive, unstabilizing chemical reactions or mechanicalreactions because these reactions are destructive. These reactions canoccur along the shale layers and sand. Chemicals, such as chlorides andbromides, may be used to delay these reactions to reduce theirdestruction.

Borehole stability is a requirement of a monodiameter wellbore. If anyportion of the borehole wall falls into the wellbore, it is difficult toachieve a monodiameter wellbore. This is prevented through the drillingfluid system. Borehole stability is achieved by the type of drillingfluid used, the geo-mechanics, the bit, the directional tool, all ofthese come into play. Chemical casing may also be used to achieveborehole stability rather than having to set a new casing string.Traditionally, some type of metal casing had to be set. However, settingadditional metal casing causes the borehole to be reduced in diameterthus ultimately reducing the production flowbore diameter. This thenreduces the reservoir production. Thus, expandables are preferred toreduce the loss of borehole diameter.

The monodiameter's fluid system must meet more and tighter parametersthan average wells, including: borehole stability in a wide variation offormation lithologies and with increased time exposure and temperaturevariations due to increased lengths to be drilled across multipleformations; ability to drill with narrower bands of equivalentcirculating densities and fracture gradient parameters; increasedefficiency of borehole cleaning and hydraulics due to longer lengths andsmaller diameters being drilled, along with reduced friction between thedrill string and borehole through the use of a more lubricious drillingfluid; bottomhole assembly cooling for the longer intervals to bedrilled; and environmental performance for the best overallwell-construction efficiencies and regulatory compliance.

Borehole stability in a wide variety of formation lithologies withincreased time exposure and temperature variation are addressed in themonodiameter method. Borehole stability is required to be able to drillin narrower bands of equivalent circulating densities with respect tofracture gradient parameters. Coals, shales, sand stringers, carbonates,reactive clays (gumbo), and more may be drilled from the surface to thereservoir barrier. The primary problems to be addressed when selecting adrilling fluid for the monodiameter well include bit balling, holeenlargement, reactive shale, and formation creep. Several of theseproblems result from mud pressure penetration. Invasion of mud filtrateand the resultant interaction with formation clays may result inborehole instability. Therefore, the mud system must produce a mud cakethat can effectively control hydraulic pressure, chemical differences,and electrical differences, in a longer time-exposure environment thantraditional drilling operations. Mud systems, such as oil-based andsynthetic-based systems, can provide this mud cake. However, traditionalwater-based mud systems cannot control hydraulic pressure, chemicaldifference and electrical differences in shales for long periods oftime. A specialty non-traditional water base mud system is required.Non-traditional water-based membrane mud systems can help prevent ionexchange between the water in the drilling fluid and shale.

Ensuring the shale pore radius and drilling mud hydrated ions radius areequivalent and the chemical potentials of the drilling fluid and shaleare the same, can help achieve these goals. Tests show pore pressuredifferentials and chemical differentials have greater membraneefficiencies and less osmotic exchanges. Understanding pore pressurechanges from the membrane mud system developments address the potentialwellbore instability problems related to longer time exposures. Theseissues must be addressed when drilling from surface casing to extendedcasing lengths (possibly to the reservoir barrier) for the monodiameterwell.

Borehole cleaning and hydraulics are essential to drilling deviatedwells with long, extended casing intervals. Smaller cuttings in aturbulent flow regime can allow the hole to be cleaned more easily in asmaller borehole (depending on effective annular spacing) vs. inlarger-diameter casing intervals that provide lower annular velocitiesseen in traditional well-construction designs. Synthetic and water-basedmud systems, along with a properly designed bit and bottomhole devicessuch as turbulators, provide efficient borehole cleanout depending onthe formation requirements.

Borehole hydraulics are considered during well planning and during thedrilling of the well. During initial monodiameter installations, themonodiameter well is not expected to be in an exploration area untilmore history is gained on the technology. Historical bit and fluidhydraulics information used with actual well surface (cuttings)information from previous wells can be valuable when planning the mudvelocities required for the monodiameter well-construction program. Thehistorical hydraulics are compared to the real-time well hydraulicsformation and directional information so that the maximum lengthpossible interval can be drilled with few difficulties.

Additionally, real-time information ahead of the bit and pressure at thebit can help the mud engineer manage the ECDs, including the fracturegradient because the engineer can apply the properly designed drillingfluid formulations. The real-time information is shared with thecementing engineer, who can then manage those zones effectively withoutmajor losses, or the zones can be handled through a chemical casingapplication, hereinafter described.

Friction between the borehole and drill string is minimized for the longmonodiameter borehole. While synthetics and oil-based systems have ahigh degree of lubricity, water-based systems generally do not. In awater-based system, lubricant additives can help minimize friction andassist in keeping the bottomhole assembly clean, allowing more efficientweight at the bit by reducing torque and drag.

The capability of the bottomhole assembly to run greater casing lengths(i.e. the entire length from surface casing to the top of the reservoir)will require the drilling fluid (mud) system to assist in cooling thebit. If bit cooling is the only characteristic considered, a water-basedmud system will not retain heat as much as a synthetic-based mud systemor oil-based mud system. Water-based mud additives that enhance wallcake and filter loss may not be as stable as other synthetics oroil-based systems at higher temperatures. Temperature plays a role inthe design of water-based additives for drilling longer casingintervals.

While the monodiameter well is being drilled, lost circulation can occurand fracture pressure can be exceeded. Real-time surface and formationmonitoring can help determine if these problems are occurring. Tomaintain the monodiameter well design, minor lost circulation problemsare resolved by incorporating lost circulation materials in the mud, orby using chemicals such as neat resins or resins incorporated in muds orlost circulation pills. If more serious lost circulation occurs,expandable casing can help seal the zone. Using the nested monodiameterexpandable casing system allows for shorter or longer intervals thanplanned without a major impact on the monodiameter overall design orsavings.

Environmental acceptance may not be considered a unique characteristicspecific to the monodiameter fluid system. However, if the drillingfluid system best achieves the well construction, but the overall costof cuttings handling, cleaning, and transport is too high, then theprimary purpose of the monodiameter well, to reduce well constructioncosts, is not fulfilled. The overall cost and benefits of the drillingfluid system must be compared from a holistic standpoint—before, during,and after drilling. A water-based mud system results in fewer oilycuttings, less transportation, and less overall environmental impact.

Drilling fluid systems that meet the monodiameter design requirementsinclude diesel, synthetic and water based systems or a blend of these.Synthetic systems include vegetable ester, internal olefin basedsystems, minerals, or a blend of any of the above. Example syntheticsinclude linear alpha olefins, internal olefins, paraffins, vegetableesters and the like. Water base systems include muds containingpolymeric viscosifiers, commercial clays, silicates, membrane efficient,or brine based systems. Examples include sodium chloride, potassiumchloride, bromides or formates. However, individual formations, regions,well objectives, and environments are considered when choosing theoptimum drilling fluid system for the individual monodiameter well.

Since the monodiameter wellbore has basically one diameter from thesurface to the reservoir barrier but may continue on to the bottom ofthe wellbore across the producing reservoir zone, the drilling fluidsare preferably “matched” to the formations that are being drilled. Ifthe formations are a water-sensitive clay or shale, the formation canslough into the wellbore if a water base fluid has been used that is notan inhibitive mud system or a oil base or synthetic base system has beenused. This situation causes large erosional sections to occur in someformations if the drilling fluids do not meet the formation boreholestability requirements.

Referring now to FIG. 7, the system includes drilling fluids, such aswater or synthetics, using a membrane efficient mud system 230 whichallows the drilling of a consistent tight borehole, i.e., a generallycylindrical borehole not given to borehole failures. The mud systemproduces a mud cake that can effectively control hydraulic pressure,chemical differences, and electrical differences, in a longertime-exposure environment than traditional drilling operations. Drillingfluid systems, such as oil-based and synthetic-based systems, canprovide this mud cake. However, traditional water damage based mudsystem can not provide these requirements in shales for long periods oftime. New water-based membrane drilling fluid systems can help prevention exchange between the water and the drilling fluid and shaledepending on the drilling time and on the drilling fluid and completionutilized.

The ability to drill with a narrow band of equivalent circulatingdensity and fracture gradient is required to be able to deliver a smoothborehole for the monodiameter casing to be installed. Other desirablecharacteristics include resistance to contamination, ability to reducehigh pressure—high temperature (HPHT) fluid loss and increased rhelogy.A vegetable ester and internal olefin based synthetic drilling fluidsystem, such as ACCOLADE, can provide these characteristics. ACCOLADE isdescribed in U.S. patent application Ser. No. 09/929,465 filed Aug. 14,2001, hereby incorporated herein by reference, and International PatentApplication Nos. PCT/US00/35609 and PCT/US00/35610, both filed Dec. 29,2000 entitled Method of Formulating and Using a Drilling Mud withFragile Gels.

Depending on the formation, oil, synthetic, or water base fluids may beutilized for drilling the monodiameter wellbore. Some of these fluidtypes include ACCOLADE—a vegetable ester and internal olefin based fluidsystem; BAR-OMEGA—a membrane efficient water base fluid system;HYDRO-GUARD—an inhibitive water-based fluid; calcium chloride basesystems that have internal breakers N-FLOW, PETROFREE LV, an ester baseddrilling fluid; BRINEDRIL N, a calcium chloride based system; aldehydebased drilling fluids; drilling fluids containing calcium chloride orpotassium chloride; or formate mud systems. All of the drilling fluidsreferred to are Halliburton drilling fluids. ACCOLADE, BAR-OMEGA,HYDRO-GUARD, BRINEDRIL N, and N-FLOW are products of Baroid. All ofthese drilling fluids interact with the formations to make a consistenttight borehole that does not have large erosional zones throughout theformation's sections. The mentioned drilling fluids minimize thoseerosional zones to provide a consistent tight borehole around the drillstring. This type borehole minimizes the large washouts and permitsbetter cementing of the casing which allows for better stability.BAR-OMEGA is described in International Patent Application No.PCT/US00/35686 filed Dec. 30, 2000 entitled Novel Compounds andAssociated Mechanisms for Generating a Highly Efficient Membrane inWater-Based Drilling Fluids. HYDRO-GUARD is described in “HalliburtonNew Technologies and General Capabilities” (5 pages).

PETROFREE, PETROFREE LV and other drilling fluids are described in U.S.Pat. Nos. 6,422,325 and 6,290,001; U.S. patent application Ser. No.09/887,138 filed Jun. 22, 2001 and entitled Methods of Using ReversiblePhase Oil Based Drilling Fluid, now U.S. Pat. No. 6,806,233; U.S. patentapplication Ser. No. 09/929,465 filed Aug. 14, 2001 and entitled Blendsof Esters with Isomerized Olefins and Other Hydrocarbons as Base Oilsfor Invert Emulsion Oil Muds; U.S. patent application Ser. No.09/939,990 filed Aug. 27, 2001 and entitled Electrically ConductiveOil-Based Mud, now U.S. Pat. No. 6,691,805; U.S. patent application Ser.No. 09/999,799 filed Aug. 31, 2001 and entitled Additive for Oil-BasedMud, now U.S. Pat. No. 6,620,770; U.S. patent application Ser. No.10/151,260 filed May 20, 2002 and entitled Methods and Composition forDelaying the Crosslinking of Crosslinkable Polysaccharide-Based LostCirculation Materials; U.S. patent application Ser. No. 10/175,272 filedJun. 19, 2002 and entitled Method of Formulating and Using a DrillingMud with Fragile Gels; all hereby incorporated herein by reference.

For additional information on other drilling fluids see U.S. Pat. No.5,925,598 entitled Water-Based Drilling Fluid for Use In ShaleFormations; U.S. Pat. No. 5,869,434 entitled Free-Flowing BoreholeServicing Preparations Containing Linear a-Olefins, More ParticularlyCorresponding Drilling Fluids; U.S. Pat. No. Re. 36,066 entitled Use ofSelected Ester Oils In Drilling Fluids and Muds; U.S. Pat. No. 5,555,937entitled Method and Combination of Materials for Releasing a Stuck Pipe;U.S. Pat. No. 5,252,554 entitled Drilling Fluids and Muds ContainingSelected Ester Oils; U.S. Pat. No. 5,252,554 entitled Drilling Fluidsand Muds Containing Selected Ester Oils; U.S. Pat. No. 5,232,910entitled Use of Selected Ester Oils in Drilling Fluids and Muds; U.S.Pat. No. 4,758,357 entitled Dispersible Hydrophilic Polymer Compositionsfor Use In Viscosifying Heavy Brines, all hereby incorporated herein byreference.

Specialized sweeps may be run in conjunction with the drilling fluids toprovide both additional hole cleaning and lost circulation mitigation.These sweeps can be formulated containing a variety of materials, suchas Sweep-Wate manufactured by Halliburton. See U.S. Pat. No. 6,290,001,hereby incorporated herein by reference, and “Halliburton NewTechnologies and General Capabilities” (5 pages). A sweep is performedafter or during the drilling phase. A sweep is used to clean up theborehole due to an accumulation of cuttings which require that theborehole be cleaned during the drilling operation. The sweep isparticularly necessary during extended reach wells which are wells thatare more horizontal thereby causing the cuttings to tend to collect.

Various techniques are used to incorporate chemical materials in theborehole to reduce the number of casing strings, which is one of theprimary goals of the MONOWELL, and to provide a diametric efficientborehole wall. During the drilling of a monodiameter borehole, chemicalsmay be employed when encountering low mechanical-strength formations,unconsolidated weak zones, or abnormal geopressure profiles that willallow extending the casing length.

Referring again to FIG. 7, problems may arise during the drilling ofvarious formations. There are shown wash out areas 232, 234 in theborehole which substantially reduce diametric efficiency. If large washouts do occur during the drilling, it may be necessary to fill in theborehole wash out areas prior to casing the borehole. Cuttings, salts,shales, excessive mud cake buildup, and washouts can result in anon-quality, non-smooth (high tortuosity) borehole. These problematicsituations conventionally require a casing string to seal the formation.In a conventional drilling process, drilling is stopped while the casingstring or liner is set, an expensive procedure that consumes rig timeand expensive materials. Additionally, the wellbore diameter is reducedwith the installation of each traditional mechanical casing string. Inthe Monowell, the interval length to be drilled is extended. An expandedcasing is applied over the problem area and the serious size reductiondoes not occur.

Wash outs and voids can be remedied using various chemical solutionsthat can be applied to the borehole which allow extending themonodiameter casing length. Such solutions include settable spottingmaterials or adhesives when the wellbore might be giving way tostresses. Settable spotting materials are materials that are pressedinto the formation that then set up. The materials and adhesives willact to stabilize the wellbore and obtain a smooth borehole so thatpermanent casing or expandable casing can be run in the monodiameterwellbore. Chemicals can be utilized during drilling to strengthenformation areas. The chemicals penetrate into the formation and yield acompressive strength to strengthen the area so as to support settingmetallic or nonmetallic (composite) casing strings. A settable spotmaterial, such as chemical casing thixotropic material, FLO-STOP,CHANNEL SEAL or a resin may be spotted in the washed out areas or othervoids.

A tough chemical casing material 236 is one solution that may beemployed in these situations. Chemical casing may be used to addressweak formations that may not allow casings to be set or have integrity.The chemical casing can increase the mechanical pressure integrity andconsolidate and isolate zones to prevent fluid migration. One form ofchemical casing is used in strengthening the formation. The chemicalcasing may also be used to strengthen a weakened casing by building achemical casing behind an existing mechanical casing.

There are several chemical casing delivery systems. One delivery systemis a spotting system where the borehole is filled with chemical casing,allowed to solidify, and then a borehole is drilled through it. Apreferred delivery system includes putting a catalyst in the drillingfluids and then later circulating a set up material to cause thechemical casing to set up. The set up material and the catalyst reactsto cause the chemical casing to solidify. Another delivery systemincludes mixing the chemical casing with the drilling mud. Still anotherdelivery system is using the chemical casing itself as the drilling mud.See U.S. patent application Ser. No. 10/170,400 filed Jun. 13, 2002 andentitled Methods of Consolidating Formations or Forming Chemical Casingor Both While Drilling, now U.S. Pat. No. 6,702,044, hereby incorporatedherein by reference. Adhesives may also be included in the drillingfluids.

In spotting the chemical casing across the problem formation, thebottomhole assembly is either removed from the borehole or raised to adepth above that section of the borehole wall to be chemically cased.The drill string may or may not be removed. In one embodiment, the drillstring may be left in the borehole and be expanded to serve as a casing.A catalytic base material and set-up material are mixed and the mixtureis pumped down the upper bore hole 10A and caused to permeate theformation around borehole wall. The mixture is then left in the borehole10A for a specific period of time. For the chemical casing to set up asa solid, it is necessary to wait a substantial period of time for thechemical casing to completely solidify. Catalyst activators can be addedto the mixture to speed up the solidification of the chemical casing.After waiting a few hours, the residue chemical casing is drilled out,such as with a drilling mud, leaving the remainder of the mixturepermeating into the borehole wall and leaving a chemical casing face onthe bore hole wall to form the chemical casing. Thus, the processincludes drilling through one of multiple formations, chemically casingthat formation, and then continuing the drilling of the borehole.

Alternatively the chemical casing solution can be applied in a two-phaseprocess. First, drilling fluid acts as a carrier for a catalyst capableof chemically adsorbing onto the weak or unconsolidated formations andforms a filter cake. Then, a water-soluble or dispersible resin-typematerial, with or without filter-cake forming solids, is circulatedacross the treated formations. The previously adsorbed catalyst curesthe resin to strengthen or consolidate the formations, and forms a curedchemical casing or seal.

Since the monodiameter wellbore has basically one diameter from thesurface to the reservoir barrier, but may continue on to the bottom ofthe wellbore across the producing reservoir zone, the chemical casing ispreferably “matched” to the formations that are being drilled.

A first preferred method utilizes a single chemical casing fluid fordrilling the well bore and simultaneously consolidating weak zones orformations at locations where it is known that unconsolidated weak zonesand formations will be encountered. A second preferred method utilizesboth a drilling fluid and a treating fluid in drilling applicationswhere it is unknown if unconsolidated weak zones or formations will beencountered. In the another method, if unconsolidated weak zones orformations are not encountered, the treating fluid step is not requiredand the time and expense required for performing the treating fluid stepwill be saved.

The first preferred method for consolidating unconsolidated weak zonescomprises drilling the well bore with a drilling fluid having a pH inthe range of from about 6 to about 10, preferably about 8. The drillingfluid is comprised of water, a polymeric cationic catalyst capable ofaccepting and donating protons which is adsorbed on the unconsolidatedformation, a water soluble or dispersible polymer which iscross-linkable by a thermoset resin and causes the resin to be hard andtough when cured, and a water soluble or dispersible thermoset resinwhich cross-links the polymer, is catalyzed and cured by the catalystand consolidates the weak zones or formations.

The water utilized to form the drilling fluid can be fresh water,unsaturated salt solutions or saturated salt solutions, including brineand seawater. Generally, water from any source can be utilized so longas it does not adversely react with components of the drilling fluid.

Examples of polymeric cationic catalysts capable of accepting anddonating protons which are adsorbed on the formation include, but arenot limited to, polyethyleneimine, poly(dimethylaminoethylmethacrylate)and poly(dimethylaminopropylmethacrylate). Of these, polyethyleneimineis preferred. The polymeric cationic catalyst is generally included inthe drilling fluid in an amount in the range of from about 1% to about15% by weight of water in the drilling fluid, more preferably in anamount in the range of from about 2% to about 10% by weight of the waterand most preferably in an amount of about 6%.

The water soluble or dispersible polymers which are cross-linked by thethermoset resins utilized in accordance with this invention are polymerscontaining one or more of hydroxyl, amide, carboxyl and epoxy functionalgroups. Examples of such polymers include, but are not limited to,acrylic latexes, polyvinylalcohol, polyvinylbutyral, polyesters,polyalkylacrylic acids, polyurethanes, acrylamide polymers, proteins,polyols and polysaccharides such as chitosan, hydroxyethylcellulose,carboxymethylhydroxyethylcellulose, water soluble starches, guar gum,xanthan gum, welan gum, carragenan gum and arabic gum. Of these,polysaccharides are preferred. The water soluble or dispersible polymerwhich is cross-linked by thermoset resins is generally included in thedrilling fluid in an amount in the range of from about 0.5% to about 20%by weight of water in the drilling fluid, more preferably in an amountin the range of from about 1% to about 10% by weight of the water andmost preferably in an amount of about 3%.

The water soluble or dispersible thermoset resins (including particulatesolid thermoset resins having a particle size in the range of from about50 to about 1000) utilized in accordance with this invention areselected from melamine-formaldehyde type resins, i.e., amino resins madefrom melamine and formaldehyde, urea-formaldehyde type resins, i.e.,amino resins made from urea and formaldehyde and phenol-formaldehydetype resins, i.e., synthetic thermoset resins made from phenol andformaldehyde. More preferably, the thermoset resins utilized areselected from alkyl ethers of melamine-formaldehyde resins and alkylethers of urea-formaldehyde resins. Of these, alkyl ethers ofmelamine-formaldehyde resins are preferred. An alkyl ether ofmelamine-formaldehyde resin which is particularly suitable iscommercially available under the tradename “ASTRO MEL CR1™” from BordenChemical of Springfield, Oreg., USA. The water soluble or dispersiblethermoset resin utilized in the above described method is generallypresent in the drilling fluid in an amount in the range of from about 5%to about 80% by weight of water in the drilling fluid, more preferablyin an amount in the range of from about 20% to about 70% by weight ofwater and most preferably in an amount of about 50%.

The thermoset resins described above, when catalyzed by heat, catalystsor other means, form substantially infusible or insoluble materialswhich do not soften on reheating. When cross-linked and cured, thethermoset polymers are strong, hard and tough.

As will be understood by those skilled in the art, the drilling fluidscan include other conventional components such as weighting materials,viscosifiers, dispersants and fluid loss control agents.

The second preferred method for consolidating unconsolidated weak zonesor formations is comprised of the following steps. The well bore isdrilled with a drilling fluid having a pH in the range of from about 6to about 10, preferably 8, and is comprised of water and a polymericcationic catalyst capable of accepting and donating protons which isadsorbed on the formation. Thereafter, the well bore is contacted with atreating fluid having a pH in the range of from about 6 to about 10,preferably 8, and comprised of water, a water soluble or dispersiblepolymer which is cross-linkable by a thermoset resin and causes theresin to be hard and tough when cured and a water soluble or dispersiblethermoset resin which cross-links the polymer, is catalyzed and cured bythe catalyst and consolidates the weak zones or formations so thatsloughing is prevented.

The components of the drilling fluid and treating fluid of the abovedescribed method, i.e., the water, the polymeric cationic catalyst, thewater soluble or dispersible polymer which is cross-linkable by athermoset resin and the water soluble or dispersible thermoset resin arethe same as those previously described.

The polymeric cationic catalyst is present in the drilling fluid in ageneral amount in the range of from about 1% to about 15% by weight ofwater in the drilling fluid, more preferably in an amount in the rangeof from about 2% to about 10% by weight of the water and most preferablyin an amount of about 6%.

The water soluble or dispersible polymer which is cross-linked by athermoset resin is present in the treating fluid in a general amount inthe range of from about 0.5% to about 20% by weight of water in thetreating fluid, more preferably in an amount in the range of from about1% to about 10% of the water and most preferably in an amount of about3%. The water soluble or dispersible thermoset resin is present in thetreating fluid in a general amount in the range of from about 5% toabout 80% by weight of the water and most preferably in an amount ofabout 50%.

The drilling fluid as well as the treating fluid can also include otheradditives which are well known to those skilled in the art such asweighting materials, viscosifiers, dispersants and fluid loss controlagents.

The drill ahead process using drill ahead material 238 is another methodthat employs field-proven chemical techniques to reach the producingobjective and eliminates the need for setting a casing string or liner.This process is performed when the drilling pressure window narrowsbetween hole-collapse pressure, pore pressure, and fracture-pressureprofiles. The process incorporates a series of pump-in and shut-instages with a chemical treatment that enters the vugs, naturalfractures, or permeability of the formation. This series of pump-in andshut-in stages is commonly referred to as leakoff tests (LOT). Thetreatments may be designed to consolidate weak zones, install protectivebarriers in water sensitive formations, isolate high pore pressures,increase wellbore pressure containment, or any combination of thesefactors. Isolating high pore pressure provides kick control when usinglower drilling mud weights. Alternatively, increasing wellbore pressurecontainment may allow the operator to mud up and reach the objectiveproducing zone without setting a liner or casing string. The drill aheadprocess may also be used to correct a weak cement shoe or a weak placein the casing and strengthen the formation around the weakness.

If the formation has shallow water flows and does not allow theformation to be open long enough for an interval to be drilledcompletely prior to the borehole collapsing, then other types ofsettable stop materials may be used such as FLO-STOP, FOAWMED SLAG,FLO-STOP 1 and FLO-STOP 5000 described in U.S. Pat. Nos. 5,588,489;5,571,318; and 6,273,191, all hereby incorporated herein by reference.

CHANNEL SEAL is a settable spottable material and is a specialized typeof cement. However, CHANNEL SEAL is not used as cement. CHANNEL SEAL isused to spot and consolidate the borehole wall. The CHANNEL SEAL is usedto fill out the wash outs or voids for stabilizing the borehole prior toinstalling regular expandable casing. CHANNEL SEAL is a Halliburtonproduct. CHANNEL SEAL can be used with expandable casing or regularcasing or in other situations where stabilization needs to occur aroundthe borehole for containment. It is preferred that CHANNEL SEAL not beused with chemical casing. CHANNEL SEAL is described in U.S. Pat. Nos.6,138,759 and 6,315,042, both hereby incorporated herein by reference.

Other mechanical borehole supports may also be used in the nestedexpandables as well as in the chemical solution cases to reduce thenumber of casing strings. Traditional casing that is used as a secondbarrier to the chemical or expandable tubulars may be employed. See FIG.17. Also, coiled tubing or continuous composite pipe may be used as aprimary or secondary barrier. Coiled tubing or continuous compositetubing has fewer potential connection leaks and may be deployed byfaster means. If real-time pore pressure and fracture gradientmanagement can be achieved, longer casing intervals can result.Traditional casing can be used, but additional stress loadings areconsidered in the design based on the longer lengths, temperaturevariations, and pressure variations.

It should be appreciated that several casing types may be used with thepresent invention to provide mechanical support in the borehole. Variousembodiments have described which include the use of conventional casing,chemical casing, and expandable casing. Traditional conventional wellarchitecture utilizes hardened non-deformable ferrous alloy casing of aspecific strength and grade for the individual formation sections.Preferably the present invention uses chemical casing and/or expandablecasing. However, various casing methods may be utilized in amonodiameter wellbore. Casing materials may include steels and/or othermetals, composites, plastics, chemicals, ferrous and non-ferrousmaterials or any other material having the characteristics required toform a casing wall. Casing materials may be coated with elastics,plastics, or teflon over metallics for corrosive purposes. The casingmaterials can be products of nanotechnology processes as well. Themethods can also be combined or separated and be temporary or permanent.

Expandable casing may be used to address borehole stability issues.Expandable casing is used in the original permanent wellboreconstruction as permanent casing. It may also be utilized to case off acollapsed wellbore, or to help maintain the final wellbore penetrationdiameter when an additional casing might be required. For example,during the well construction process, the earth might collapse or casingwear may occur leaving a hole in the original permanent constructedbarrier. A new barrier will be required. Expandable casing will allowthe final diameter of the reservoir penetration to be maintained. Ifconventional casing is utilized, it is unlikely the final penetrationdiameter can be maintained across the reservoir.

Casing methods also include mechanical casing while drilling which mayor may not include the expansion of casing during or after drilling.Further, composite tubulars may be used as the casing, which may or maynot be expanded during the well construction process. Composite tubularsare made by Fiber-Spar and Wellstream, but may be made by others. Thus,composite tubulars may be expanded across a formation. Still further,the borehole wall may be cased by fusion, such as lasers, during orafter drilling. Still another method includes drilling with casing thatincludes the use of drill string as casing, which may or may not beexpanded during the construction process. A further method includes theuse of extrusion materials where the wellbore may be lined with extrudedmaterial during the well construction process. The extruded material mayremain permanently in the wellbore. Another method includes the use oftelescoping lining materials resulting in a tapered wellbore. Thetapered wellbore, however, still maintains the nominal limits of amonodiameter wellbore. Telescoping liners are a series of liners eachwith a slightly smaller inner diameter. Expandable liner hangers may beused to help with the telescoping.

It should also be appreciated that the casing may be installed in one ofseveral ways. For example, the casing may be run utilizing a drillingrig. It may also be installed using detachable conductor pipe in aratchetable configuration. The casing may also be installed by drill andcase methods employed by Sperry and Halliburton. Also, casing may bedriven down into the formation or may be washed down. The casing mayalso be deployed utilizing a propulsion system. See U.S. Pat. No.6,003,606 and U.S. patent application Ser. No. 10/265,786 filed Oct. 7,2002 entitled Well System, both hereby incorporated herein by reference.Casing can be installed using coiled tubing, a workover unit, ahydraulic workover, for example. Casing may be installed by using asuction embodiment device, which may include a detachable conductor pipein a ratchetable configuration. See U.S. patent application Ser. No.10/193,609 filed Jul. 11, 2002 and entitled Retrievable SuctionEmbedment Chamber Assembly, now U.S. Pat. No. 6,659,182, herebyincorporated herein by reference.

Other equipment used with the present invention includes a wellhead tosupport and hang off subsea/surface tubulars, provide structuralsupport, support casing, and support tubing. Due to the small diameterannulus and the reduced number of annuli by the longer length drilledwell section, the casing hangoffs and tubing hanger may be expanded orspecially machined. The wellhead also may be reduced in size reducingthe required rig load capacity. Traditional wellhead equipment might beutilized as well. An expandable tubing hanger may be used but is notnecessarily preferred.

Expandable casing may be installed within the wellbore by cladding andmay not necessarily be cemented in place. If the expandable casing has aconstant diameter outer borehole, it will still constitute amonodiameter wellbore.

The narrow annuli for expandable casing/liners require that othersealing compositions or isolation materials be used. Such compositionsand materials must be ductile in order to form an appropriate seal. Itis preferred that conventional cement is not used with expandable casingas micro annuli can develop, allowing for gas migration and poorisolation. Oil field cement will be particularly brittle and weak insuch thin sheaths and is hence an inappropriate sealing medium. Theformulation for the expandable casing cement is different from regularcement.

Cementing of the casing may be achieved by various methods including theuse of sealants, settable spot technology, conventional primarycementing, resins, foam cement, latex, and mud to cement formulations.These materials may be dispensed through the drill bit, an activatedsub, an applicator, or a brush system.

Several considerations are made when cementing the longer upperinterval(s) in the MONOWELL, including: What will the well (and cementbarrier) have to endure during its lifetime? What effect will theincreased length and temperature variations have on cementing stressloading and integrity? What cement chemical formulations characteristicsare required? What execution practices may be applied that reduce flattime? The specific goal for the MONOWELL is to reduce lifetime cost perequivalent unit of oil or gas by increasing efficiencies. To achievethis goal, the entire well construction and long-termproduction/injection is considered.

Longer casing and cementing intervals have to endure temperature andpressure variations, including shrinkage and expansion, as well asbonding to varied formations and different mechanical and chemicalstructural supports. Cements with a high Young's Modulus are moresusceptible to damage from pressure and temperature changes. The Young'sModulus may also be important in cases where sealants may be applied.Foamed cements have good elastic behavior. Mechanical responses havebeen modeled, including bonding, cracking, plastic deformations,shrinkage and expansion. A finite elemental analysis and designprocedure are performed in the MONOWELL cementing program to estimaterisk of cement failure as a function of formation properties, cementsheath, and well stress loading, but various formations, temperatures,pressures, loadings, mechanical/chemical bondings, and well functionsmust be accounted for in the finite elemental analyses. This approachbest helps operators determine optimum MONOWELL cement formulation thattransverses across multi-formations and longer lengths.

Due to the consistent wellbore for the monodiameter architecture,several factors are considered in the cementing analyses: the cementingwill be conducted in smaller annuli spacing; the cementing willexperience more rapid thermal cycling; and the cement composition willhave to be geared more to a “life of the well approach” in a more severeexposed condition. All of these factors have to be taken into accountduring the engineering and design process.

Cement slurry density is often greater than the density of the drillingfluids (mud) used to drill the interval. Longer casing string intervalscan further increase ECDs during cementing because of increasedhydrostatic column height. In many cases, the performance propertiesrequired for a specific application can be achieved with lightweightslurries. High compressive strength, often achieved with higher-densityslurries, may not always be the primary consideration.

The type of structural mechanical support will be relevant when cementformulations are selected. In the expandable tubular case, cementingwill have to endure compression forces and not be so hardened thatinduced long-term cracking occurs. Therefore, cement slurries should bedesigned to match the formation and mechanical support in achieving adesired Young's Modulus and bond.

In either case, bonding at the varying formations to the cementinterface, and cement to mechanical (or chemical) structural supportinterfaces, must be considered. Whether a single base cement withvarying additives can be formulated to handle the various formations aredetermined for the specific well and location.

Further, it is preferred that the drilling fluid is an easy-to-displacetype fluid for displacement to occur through the narrower annulus. Thiswill permit wellbore displacement from drilling fluids to cement fluidsto occur. In an unconsolidated formation, areas of the drilled boreholemay expand to a diameter of 18 to 36 inches, as for example. It ispreferred that the borehole for the present invention not have adiameter greater than about 12 to 13 inches for 10¾ inch casing. Thusthe drilling fluid needs to be easy to move through the annulus butstill maintain the properties of being able to maintain well control,keep borehole stability, for example.

Also, a drilling fluid that generates a thin filter cake is required. Ifa thick filter cake is developed, it will slough off resulting in largeerosional holes that are difficult or impossible to cement uniformly.Because it is difficult to move fluid through the annulus, the mostmovable or flowable drilling fluid is preferred so that it will pass andflow through all of the annular areas and gaps around the drill string.Displacement from drilling fluids to cement will require a “clean”differential phase between the two fluids to get a smooth cleandisplacement. While displacement normally occurs going down the drillstring and back up the annulus in a typical well, displacement for themonodiameter well can occur traditionally or by the reverse circulationmethod, i.e., down the annulus and returns back up the drill string,particularly where there are excessively long intervals to cement.

Cementing execution for the longer cementing interval preferably startswith a chemical spacer that has been designed specifically toefficiently clean the hole of the specialized drilling fluid anddisplace the borehole for the new cement. Incorrect displacement orincompatibilities of the drilling fluid and cement can result in acostly, poor cement job.

The spacers provide a barrier between the drilling fluids and the cementso that the cement does not contaminate the drilling fluid. Whileflowing drilling fluid, channels or stringers of the drilling fluid andcement can mix together due to turbulent flows. Stringers between thedrilling fluid and cement will result in the cement having poorcompressive strength or poor integrity. To avoid this mixing, a spaceris run between the drilling fluid and the cement serving as a barrierbetween the two fluids. The spacer is a differentiating fluid, which, asit is pumped through the annulus, pushes the drilling fluids, pushes thespacer and displaces with the cement or sealant composition or material.This ensures that the cement is clean as it passes up or down theannulus.

The drilling fluid is then circulated out of the annulus followed by thecement. Some cement can be a foam that is light. It may be lighter thanthe drilling fluid. Thus the drilling fluid will tend to remain in theannulus since it is a heavier fluid then the foam cement. A spacer ispreferably used to separate the drilling fluids from the foam cement.

Reverse circulating the cement slurry (reverse circulation) is analternative method for placing cement in the MONOWELL. This technique isemployed when (1) ECDs need to be reduced to prevent formation breakdownor (2) long intervals of casing require cement with significanttemperature differences from bottom to top of cement. Reversecirculating displacement mechanics of velocity and slurry rheology aremaximized due to the hydraulics from the hydrostatic pressure of thecement slurry. The reverse circulating cement does not subject theentire slurry system to bottomhole circulating temperatures. Therefore,this technique maximizes the ability to place cement slurries designedfor the specific formation's mechanical characteristics and temperatureprofiles.

The monodiameter well architecture presents specific challenges tocementing a wellbore. There will be longer cementing sections sincethere may be as much as two or three formation sections in the wellbore.The annulus between the casing and borehole wall will be narrow forpumping the cement between the casing and the wellbore resulting insometimes slower pump rates and limited pressures. High pump rates canresult in high equivalent circulating density (ECD) that overpressurizesthe fracture gradient when pumping the cement into the formation. Slowpump rates may be required due to the narrow annulus. A slow pump raterequires special retarders so the cement will not set up or become hardwhile it is being pumped. The retarders must allow the cement to bepumped but also must allow for the cement's compressive strength todevelop after the cement has arrived at its permanent location in theannulus. Further, the standoff from the wellbore and centralization mayor may not be possible due to the annulus spacing. Conventional cementrelies upon hydraulics to flow the cement through the annulus. Thesealing composition of the present invention is a fluid which flows toany gaps between the expandable casing and borehole wall. A spottablematerial such as CHANNEL SEAL is used prior to cementing to close anywash-outs in the borehole wall.

Extended reach and horizontal wells may require the casing to be floatedin using a buoyancy system. One might consider the BACE system (abalanced buoyancy system), U.S. patent application Ser. No. 09/655,623filed Aug. 31, 2000 and entitled Methods and Apparatus for Creating aDownhole Buoyant Casing Chamber, now U.S. Pat. No. 6,505,685, herebyincorporated herein by reference. A float and buoyancy system may beutilized and may be made of a composite material.

In using expandable casing, compressing the metallic casing across thecement can create the problem of microfracturing the cement andincomplete cement integrity in some cases if the cement formulation doesnot allow for delayed setting, resistance, and elasticity. Sealants maybe utilized in some cases. The cement formulations must thus be specificfor expandable casing operations including the narrower annulus thatwill be in a monodiameter well.

Referring now to FIG. 8, one preferred sealing composition 240 forexpandable casing/liners is described in U.S. patent application Ser.No. 10/006,109 filed Dec. 4, 2001 entitled Resilient Cement, now U.S.Pat. No. 6,668,928; U.S. patent application Ser. No. 10/243,001 filedSep. 13, 2002 entitled Methods and Compositions for Sealing AnExpandable Tubular in A Well Bore; both hereby incorporated herein byreference. The sealing composition comprises a mixture of latex, dithiocarbamate, zinc oxide, and sulfur, for sealing a subterranean zonepenetrated by a well bore. The sulfur containing component vulcanizesthe latex to form a solid. The latex preferably includes astyrene/butadiene copolymer latex emulsion prepared by emulsionpolymerization. The ratio of styrene to butadiene in the latex can rangefrom 10:90 to 90:10. The emulsion is a colloidal dispersion of thecopolymer. The colloidal dispersion includes water from about 40-70% byweight of the emulsion. In addition to the dispersed copolymer, thelatex often includes small quantities of an emulsifier, polymerizationcatalysts, chain modifying agents and the like. Also, styrene/butadienelatexes are often commercially produced as ter-polymer latexes whichinclude up to about 3% by weight of a third monomer to assist instabilizing the latex emulsions. The latex may be of any variety of wellknown rubber materials commercially available which contain unsaturationin the backbone of the polymer. Non-ionic groups which exhibit steariceffects and which contain long ethoxylate or hydrocarbon tails can alsobe present. The sealing composition may further comprise stearic acid.The weighting agent may be silica flour or alternatively manganese oxideweighting additive or still further alternatively crystalline silica.The sealing composition may further comprise acetylenic alcohol fordefoaming.

In another embodiment disclosed in U.S. patent application Ser. No.10/006,109, now U.S. Pat. No. 6,668,928, the sealing compositionincludes a mixture of latex, dithio carbamate, zinc oxide, sulfur, and afoaming agent, wherein the mixture is foamed. Further, the compositionmay comprise a weighting agent. The sealing composition is compressiblein its set state when placed against a porous geological formation, andthe alternative embodiment of the sealing composition is compressible inboth set and unset states when placed in a sealed system.

In another embodiment disclosed in U.S. patent application Ser. No.10/243,001, a sealing composition according to the present embodimentbasically comprises a polymer and metal containing compound. Aparticularly preferred sealing composition comprises a mixture of latex,dithio carbamate, zinc oxide, and sulfur, for sealing a subterraneanzone penetrated by a wellbore. The sulfur containing componentvulcanizes the latex to form a solid mass which seals the zone.Preferred polymeric sealing compositions of the present invention areresilient with comparable strength to cement but have greater elasticityand compressibility for use in cementing expandable casing.

As will be understood by those skilled in the art, polymeric sealingcompositions of the present invention may include any of a variety ofwell known polymers including, but not limited to, copolymers,terpolymers and interpolymers. Latex is preferably used for eitherembodiment and may be any of a variety of well known rubber materialscommercially available which contain unsaturation in the backbone of thepolymer. These include natural rubber (cis 1,4-polyisoprene), modifiedtypes thereof, synthetic polymers, and blends of the foregoing. Thesynthetic polymers include styrene/butadiene rubber, polybutadienerubber, neoprene rubber, acrylonitrile/butadiene rubber, polyisoprenerubber, isobutylene/isoprene rubber, and ethylene/propylene rubber.Additional polymers suitable for either embodiment include an ethylenepropylene diene polymer, an isobutylene-isoprene copolymer, halogenatedderivatives of an isobutylene-isoprene copolymer, a butadiene-isoprenecopolymer, a poly(isobutylene-costyrene) polymer, halogenatedderivatives of a poly(isobutylene-co-styrene)polymer, apoly(isobutylene-co-alkyl styrene)polymer, halogenated derivatives of apoly(isobutylene-co-alkyl styrene)polymer, apoly(isobutylene-co-haloalkyl styrene)polymer and halogenatedderivatives of a poly(isobutylene-co-haloalkyl styrene)polymer.Preferably, the halogenated derivatives are halogenated with chlorine orbromine.

The metal containing compounds of the present invention may comprisezinc, tin, iron, selenium magnesium, chromium, nickel, or cadmium.Further, the compounds may be in the form of an oxide, carboxylic acidsalt, a complex with a dithiocarbamate ligand, or a complex with amercaptobenzothiazole ligand.

The methods of the present invention for sealing an expandable tubularsuch as a pipe, pipe string, casing, liner or the like in a wellbore ina subterranean formation basically comprise placing the expandabletubular in the wellbore, placing a sealing composition as describedherein into the wellbore, expanding the expandable tubular, and allowingthe sealing composition to set in the wellbore. The methods mayoptionally comprise the step of foaming the sealant composition using agas such as nitrogen or air. In performing the described methods, thestep of placing the expandable tubular in the wellbore may be performedbefore or after the step of placing the sealing composition into thewellbore. The step of expanding the expandable tubular may also beperformed before or after the step of placing the sealing compositioninto the wellbore. Furthermore, the expandable tubular may be expandedbefore, after or during the set of the sealing composition. Where thetubular is expanded during or after the set of the sealing composition,preferred resilient compositions of the present invention will remaincompetent due to their elasticity and compressibility.

In addition to the foregoing methods, the wellbore may extend or beadditionally extended into the subterranean formation below the firsttubular wherein a second tubular, such as a pipe, pipe string, casing,liner or the like, is placed in the wellbore below the first tubularsuch that a portion of the second tubular extends into the firsttubular. A second sealing composition, in accordance to the embodimentsdescribed herein, is placed in the wellbore located below the firsttubular and the second tubular is expanded in the wellbore. The step ofplacing the second tubular in the wellbore may be performed before orafter the step of placing the second sealing composition into thewellbore and the step of expanding the second tubular may also beperformed before or after the step of placing the second sealingcomposition into the wellbore. The second tubular may also be expandedbefore, after or during the set of the either sealing composition.Furthermore, although the first and second tubulars may be expanded atthe same time, when the second tubular is expanded inside the previouslyexpanded first tubular, the second tubular may provide additionalexpansion to an overlapping portion of the first tubular whereby thesealing composition located behind that overlapping portion of the firsttubular is further compressed thereby but remains competent due to itselasticity and compressibility.

Methods for sealing expandable pipe are disclosed in U.S. patentapplication Ser. No. 10/177,568 filed Jun. 21, 2002 entitled Methods ofSealing Expandable Pipe in Well bores and Sealing Compositions, now U.S.Pat. No. 6,722,433, hereby incorporated herein by reference. Onepreferred method for sealing an expandable pipe, such as a casing orliner in a wellbore, includes first placing the expandable pipe in thewellbore and then flowing a compressible hydraulic cement sealantcomposition, which remains competent when compressed, through theannulus between the well bore and the pipe. The sealant composition isallowed to harden into an impermeable mass and thereafter, theexpandable pipe is expanded whereby the hardened sealant composition iscompressed.

In another method disclosed in U.S. patent application Ser. No.10/177,568, now U.S. Pat. No. 6,722,433, an expandable casing is placedin the well bore. A compressible foamed sealant composition, comprisedof a hydraulic cement, a rubber latex, a rubber latex stabilizer, a gasand a mixture of foaming and foam stabilizing surfactants, is thenplaced in the annulus between the well bore and the casing. Theexpandable casing is expanded and the foam sealant composition iscompressed upon the expansion of the expandable casing.

Examples of the hydraulic cement that can be utilized in the abovemethods include, but are not limited to, calcium aluminate cement,Portland cement, and Portland blast furnace cement. Of these, calciumaluminate cement is preferred. A variety of well known rubber latexescan be utilized including styrene/butadiene copolymer latex emulsion,polychloroprene emulsion, polyisoprene emulsion andacrylonitrilibutadiene emulsion. Of these, styrene/butadiene latexemulsion is preferred. In order to prevent the aqueous latex fromprematurely coagulating and increasing the viscosity of the foamedsealant composition, an effective amount of latex stabilizing surfactantis included in the composition. The latex stabilizing surfactantutilized is included in the foamed sealant composition in the range fromabout 3% to 6% by weight of the rubber latex in the foamed sealantcomposition, preferably in an amount of 4%. The gas in the compressiblefoamed sealant composition can be air or nitrogen with nitrogen beingpreferred. Various mixtures of foam and foam stabilizing surfactants canbe utilized in the compressible foamed sealant compositions. A mixtureof ethoxylated alcohol ether sulfate surfactant, an alkyl or alkeneamidopropyl betaine surfactant and an alkyl or alkene amidopropyldimethyl amine oxide surfactant is preferred. The compressible foamsealant composition can also include a viscosity increasing agent forsuspending particulate solids therein. A bentonite is preferred. Thecompressible foam sealant composition can also include a particulatesolid density adjusting weighting material suspended therein. Iron oxideis preferred. The compressible foamed sealant composition can alsoinclude a set retarder. Citric acid is preferred. A variety of otherconventional additives can also be utilized in the compressible foamedsealant composition including, but not limited to, fluid loss controladditives, accelerators, dispersants, and lost circulation materials.

In the methods, the expansion of the expandable pipe compresses the gasin the foamed sealant composition but the composition maintains itscompetency, i.e., its integrity and sealing properties, whereby itprevents the undesirable migration of fluids between zones or formationspenetrated by the wellbore and physically supports and positions thepipe in the well bore.

Sensors may be disposed in the annular area from and including thecasing wall to the borehole wall for measuring and collecting data andinformation useful in the drilling, completion, production and workoverof the well. For example sensors may be disposed in the casing/linerwall, on the exterior surface of the casing/liner, in the cement orsealing composition in the annulus, in the chemical casing, in thedrilling fluid or in the chemical on or reacted to the well bore wall.The sensors may be within the metallurgy of the metal casing or embeddedin the wall of composite casing. Sensors can be disposed in the chemicalsolutions for the borehole. Sensors also can be disposed in the cementor sealing composition as well as the chemical casing. The sensors mayalso be disposed on the outside of the monodiameter casing using asheath. These sensors may be disposed either in the upper boreholesection or in the lower borehole section extending through the producingformation.

The sensors may be of various types. One type of sensor may be madeusing nanotechnology. The sensors are not necessarily metallic sensorsbut may be a plasma, a fluid or chemical or particles or particulates.The sensors do not need to be electrical. The data or information fromthe sensors is acquired by various means such as using acoustics,vibration technology, broadband technology, radio frequency technologyor the like. The sensors do not require wires or other conductors totransmit or store the data and information of the sensors.

The sensors may be used to gather any type of down hole parameters,reservoir or seimic or the condition of equipment installed or run inthe wellbore. The sensors are disposed in the well during the drillingof the well. The signals being sent by the sensors during drilling wouldbe propagated towards the surface or to another receiver for providinginformation during the drilling of a well. The sensors may be used toidentify fractures or faults in the formation as well as seismic data ofthe formation. For example, a new well may be drilled adjacent anexisting well. The sensors may be both in the existing well and in thewell being drilled. The well being drilled is drilled by a bottom holeassembly having MWD and LWD tools which are able to receive the signalsfrom the sensors in the adjacent well. The sensors may measure the speedof the transmission of waves or vibrations between the two wells. Theyalso may detect a flood front propagating between the wells. Forexample, water may be injected in one well causing the water to flow toa producing well. The sensors are able to detect whether good sweepefficiencies are being achieved such as recovery sweeps. The sensors mayalso gather information relating to drilling. Also sensors will beuseful where the well is in a highly corrosive area. The sensors mayindicate whether the borehole is going to wash out or corrosion hasoccurred.

The above described methods and apparatus are utilized to drill andcomplete a monodiameter wellbore with a quality borehole which hasdiametric efficiency. The following describe various apparatus andmethods of casing the monodiameter borehole with a monodiameter casing.Upon reaching the formation barrier, a monobore production deliverysystem may be used in the monodiameter casing to create a MONOWELL, ashereinafter described in detail.

FIGS. 3 and 9A-G illustrate the various stages of the drilling andcompletion method of one preferred embodiment of the present invention.FIGS. 9A-G and 3 show the sequential stages or steps in drilling andcompleting the well. FIGS. 3 and 9A-G are exemplary of one preferredmethod and apparatus of the present invention. Although the method andapparatus of the present invention are equally applicable to land wellswhere the rig is land based or to offshore wells where the rig is on anoffshore platform or vessel, for purposes of description, FIGS. 3 and9A-G illustrate an example of a land based well.

Integrated MONOWELL technologies can be deployed through a traditionaloffshore rig, traditional land rig, hydraulic workover, coiled tubingunit, or wired composite coiled tubing. In the traditional offshore andland rigs, the reduced mud volumes effectively decrease rigrequirements. Drill-and-case systems can provide an added benefit toconstructing the MONOWELL, such as reducing trips and drill pipe. Thegeneral principles of increasing well-construction efficiency aresupported and are considered when designing a specific MONOWELL. Whiletraditional rigs can be used to drill the MONOWELL reservoir sections,additional benefits are derived from using wired composite coiled tubingand underbalance techniques hereinafter described.

Although the well 12 may be formed using various drilling equipment anddrilling techniques, FIGS. 3 and 9A-G illustrate a downhole assembly 20disposed on the end of a work string 22. The work string 22, forexample, may be jointed pipe 29 extending from the surface 14 from a rig34, or a drill ship in the case of a subsea well. Referring particularlyto FIG. 9A, the downhole assembly 20 may include directional drilling(i.e. mud motors), a geo-pilot or formation evaluation tools. Preferablydownhole assembly 20 includes a bit 24, a downhole motor 26, a near bitreamer 28, a measurement while drilling assembly (MWD) 30, and a loggingwhile drilling assembly 32 (LWD). It should be appreciated that the bitmay be a ferrous or non-ferrous bit and it may or may not includesensors. MWD tools determine the location of the bit in relation to thedepth and the LWD tools include logging tools for formation evaluation.The downhole assembly 20 may also include directional tools above orbelow the LWD assembly 32. It should also be appreciated that thedownhole assembly 20 may include “ahead of the bit” technology ofHalliburton where the MWD assembly 30 and LWD assembly 32 are measuringdownhole parameters in advance of the bit such as by sending pulse wavesinto the formation ahead of the bit and measuring LWD and seismicparameters. The downhole assembly may include point the bit technologyapplied from the Geo-Pilot, rotary steerable device as well.

Although the near bit reamer 28 may be located between the bit 24 andthe motor 26, it is preferably located above the motor 26. Although anear bit reamer is preferred, it is not required. One advantage of thenear bit reamer 28 is that the near bit reamer allows the borehole to beback reamed while applying chemical casing, as hereinafter described, orit can be used during the drilling of the formation to clean out anyexcess formation damage or to smooth out an unsmooth borehole to makethe borehole smoother for the expandable casing, expandable screen orcompletion to be applied.

It should be appreciated that chemical casing may be applied at any timeduring the drilling of the borehole as hereinafter explained.

Preferably the bit 24 and downhole motor 26 are a SLICKBORE bit, withmatching mud motor assembly where the mud motor assembly 26 is attacheddirectly to the bit 24. This combination minimizes tortuosity in theborehole 10 so that the borehole diameter can be consistent and smooth.A slick bore bit is preferred for the non-producing borehole 10A for thefirst 14,000 ft. A GEO-PILOT, rotary steerable device, with an extendedlong gauge bit, is preferred for longer depths.

Although not required for the non-producing borehole 10A, the slick borebit 24, or Geo pilot/bit, is utilized when drilling the producingborehole 10B through the reservoir producing zone 30. The SLICKBORESystem includes a bit 24 and mud motor 26, which are preferably matchedunits, to avoid the bit tending to drill in one direction while themotor tends to move in another direction introducing tortuosity into theborehole. The SLICKBORE System and the GeoPilot System are part of thefull drift drilling systems that produce a quality borehole. Tortuositycreates pockets in the borehole wall allowing borehole washouts suchthat the casing is not properly supported in the borehole. Perfectcementing support is difficult to achieve where there is tortuosity.

Referring now to FIGS. 10 and 11, FIG. 10 shows a bottom hole assemblyhaving a positive displacement motor (PDM) driven by pumping downholefluid through the motor for rotating the bit, and FIG. 11 shows a BHAwith a rotary steerable device (RSD) such that the bit is rotated byrotating the drill string at the surface. The BHA lower housingsurrounding the rotating shaft is preferably “slick” in that it has asubstantially uniform diameter housing outer surface without stabilizersextending radially therefrom. The housing on a PDM has a bend. The bendon a PDM occurs at the intersection of the power section central axisand the lower bearing section central axis. The bend angle on a PDM isthe angle between these two axis. The housing on an RSD does not have abend. The bend on an RSD occurs at the intersection of the housingcentral axis and the lower shaft central axis. The bend angle on an RSDis the angle between these two axes. The bottom hole assembly includes along gauge bit, with the bit having a bit face having cutters thereonand defining a bit diameter. and a long cylindrical gauge section abovethe bit face. The total gauge length of the bit is at least 75% of thebit diameter. The total gauge length of a drill bit is the axial lengthfrom the point where the forward cutting structure reaches full diameterto the top of the gauge section. At least 50% of the total gauge lengthis substantially full gauge. Most importantly, the axial spacing betweenthe bend and the bit face is controlled to less than twelve times thebit diameter.

Referring now to FIG. 10, there is shown a SLICKBORE system including abottom hole assembly (BHA) 310 having a positive displacement motor(PDM) 312 which is conventionally suspended in the well from thethreaded tubular string, such as a drill string 344, althoughalternatively the PDM 312 may be suspended in the well from coiledtubing. PDM 312 includes a motor shaft 354 and a motor housing 314having a substantially cylindrical outer surface along at leastsubstantially its entire length. The motor housing 314 includes radiallyopposing flats 353. The motor has an upper power section 316 whichincludes a conventional lobed rotor 317 for rotating the motor outputshaft 315 in response to fluid being pumped through the power section316. Fluid thus flows through the motor stator to rotate the axiallycurved or lobed rotor 317. A lower bearing housing 318 houses a bearingpackage assembly 319 which comprising both thrust bearings and radialbearings. Housing 318 is provided below bent housing 330, such that thepower section central axis 332 is offset from the lower bearing sectioncentral axis 334 by the selected bend angle. This bend angle isexaggerated in FIG. 10 for clarity, and is less than about 1.5 degrees.FIG. 10 also simplistically illustrates the location of an MWD system340 positioned above the motor 312. The MWD system 340 transmits signalsto the surface of the well in real time. The BHA 310 also includes adrill collar assembly 342 providing the desired weight-on-bit (WOB) tothe rotary bit and may include an orientation tool 346. The majority ofthe drill string 344 comprises lengths of metallic drill pipe, andvarious downhole tools, such as cross-over subs, stabilizer, jars, etc.,may be included along the length of the drill string.

The term “motor housing” as used herein means the exterior component ofthe PDM 312 from at least the uppermost end of the power section 316 tothe lowermost end of the lower bearing housing 318. The motor housingdoes not include stabilizers thereon, which are components extendingradially outward from the otherwise cylindrical outer surface of a motorhousing which engage the side walls of the borehole to stabilize themotor. These stabilizers functionally are part of the motor housing, andaccordingly the term “motor housing” as used herein would include anyradially extending components, such as stabilizers, which extend outwardfrom the otherwise uniform diameter cylindrical outer surface of themotor housing for engagement with the borehole wall to stabilize themotor.

The bent housing 330 thus contains the bend 331 that occurs at theintersection of the power section central axis 332 and the lower bearingsection central axis 334. The selected bend angle is the angle betweenthese axes. In a preferred embodiment, the bent housing 330 is anadjustable bent housing so that the angle of the bend 331 may beselectively adjusted in the field by the drilling operator.Alternatively, the bent housing 330 could have a bend 331 with a fixedbend angle therein.

The BHA 310 also includes a rotary bit 320 having a bit end face 322. Abit 320 includes a long gauge section 324 with a substantiallycylindrical outer surface 326 thereon. Fixed PDC cutters 328 arepreferably positioned about the bit face 322. The bit face 322 isintegral with the long gauge section 324. The total gauge length of thebit is at least 75% of the bit diameter as defined by the fullestdiameter of the cutting end face 322, and preferably the total gaugelength is at least 90% of the bit diameter. In many applications, thebit 320 will have a total gauge length from one to one and one-halftimes the bit diameter. The total gauge length of a drill bit is theaxial length from the point where the forward cutting structure reachesfull diameter to the top of the gauge section 324, which substantiallyuniform cylindrical outer surface 326 is parallel to the bit axis andacts to stabilize the cutting structure laterally. The long gaugesection 324 of the bit may be slightly undersized compared to the bitdiameter. The substantially uniform cylindrical surface 326 may beslightly tapered or stepped, to avoid the deleterious effects oftolerance stack up if the bit is assembled from one or more separatelymachined pieces, and still provide lateral stability to the cuttingstructure. To further provide lateral stability to the cuttingstructure, at least 50% of the total gauge length is consideredsubstantially full gauge.

The preferred drill bit may be configured to account for the strength,abrasivity, plasticity and drillability of the particular rock beingdrilled in the deviated hole. Drilling analysis systems as disclosed inU.S. Pat. Nos. 5,704,436, 5,767,399 and 5,794,720, all herebyincorporated herein by reference, may be utilized so that the bitutilized, may be ideally suited for the rock type and drillingparameters intended. The long gauge bit acts like a near bit stabilizerwhich allows one to use lower bend angles and low WOB to achieve thesame build rate.

Sensors may be preferably used when placed in a sealed hearing rollercone bit. Sensors that measure the temperature, pressure, and/orconductivity of the lubricating oil in the roller cone bearing chambermay be used to make measurements indicative of seal or bearing failureeither having occurred or being imminent.

Referring now to FIG. 11, the driving source for rotating the bit is nota PDM motor, but instead a rotary steerable application, with the rotarysteerable housing 412 receiving the shaft 414 which is rotated byrotating the drill string at the surface. Various bearing members 420,474, 472 are axially positioned along the shaft 414. Again, thoseskilled in the art should understand that the rotary steerable mechanismshown in FIG. 11 is highly simplified. The bit 460 may include varioussensors 466, 468 which may be mounted on an insert package 462 providedwith a data port 464.

The slick bore concept may also be applied to rotary steerableapplications. A rotary steerable device (RSD) is a device that tilts orapplies an off-axis force to the bit in the desired direction in orderto steer a directional well while the entire drill string is rotating.Typically, an RSD will replace a PDM in the BHA and the drill stringwill be rotated from surface to rotate the bit. There may becircumstances where a straight PDM may be placed above an RSD forseveral reasons: (1) to increase the rotary speed of the bit to be abovethe drill string rotary speed for a higher RQP; (ii) to provide a sourceof closely spaced torque and power to the bit; (iii) and to provide bitrotation and torque while drilling with coiled tubing.

FIG. 11 depicts an application using a rotary steerable device (RSD) 410in place of the PDM. The RSD has a short bend to bit face length and along gauge bit. While steering, directional control with the RSD issimilar to directional control with the PDM. The primary benefits of thepresent invention may thus be applied while steering with the RSD.

An RSD allows the entire drill string to be rotated from surface torotate the drill bit, even while steering a directional well. Thus anRSD allows the driller to maintain the desired toolface and bend angle,while maximizing drill string RPM and increasing ROP. Since there is nosliding involved with the RSD, the traditional problems related tosliding, such as discontinuous weight transfer, differential sticking,hole cleaning, and drag problems, are greatly reduced. With thistechnology, the well bore has a smooth profile as the operator changescourse. Local doglegs are minimized and the effects of tortuosity andother hole problems are significantly reduced. With this system, oneoptimizes the ability to complete the well while improving the ROP andprolonging bit life.

FIG. 11 depicts a BHA for drilling a borehole in which the RSD 410replaces the PDM 312. The RSD in FIG. 11 includes a continuous, hollow,rotating shaft 414 within a substantially non-rotating housing 412.Radial deflection of the rotating shaft within the housing by a doubleeccentric ring cam unit 474 causes the lower end 422 of the shaft 414 topivot about a spherical bearing system 420. The intersection of thecentral axis of the housing 430 and the central axis 424 of the pivotedshaft below the spherical bearing system defines the bend 432 fordirectional drilling purposes. While steering, the bend 432 ismaintained in a desired toolface and bend angle by the double eccentriccam unit 474. To drill straight, the double eccentric cams are arrangedso that the deflection of the shaft is relieved and the central axis 424of the shaft below the spherical bearing system is put in line with thecentral axis 430 of the housing 412. The features of this RSD aredescribed below in further detail.

The RSD 410 in FIG. 11 includes a substantially non-rotating housing 412and a rotating shaft 414. Housing rotation is limited by ananti-rotation device 416 mounted on the non-rotating housing 412. Therotating shaft 414 is attached to the rotary bit 460 at the bottom ofthe RSD 410 and to drive sub 417 located near the upper end of the RSDthrough mounting devices 418. A spherical bearing assembly 420 mountsthe rotating shaft 414 to the non-rotating housing 412 near the lowerend of the RSD. The spherical bearing assembly 420 constrains therotating shaft 414 to the non-rotating housing 412 in the axial andradial directions while allowing the rotating shaft 414 to pivot withrespect to the non-rotating housing 412.

While steering, directional control is achieved by radially deflectingthe rotating shaft 414 in the desired direction and at the desiredmagnitude within the non-rotating housing 412 at a point above thespherical bearing assembly 420. Deflection may be achieved using adouble eccentric ring cam unit 474.

The method of forming monodiameter wellbore 10 includes drilling amonodiameter non-producing borehole 10A from the surface 14 to thereservoir barrier 16, preferably in one trip into the well, usingdownhole assembly 20. After the non-producing wellbore 10A has beenformed as shown in FIG. 3, the work string 22 and downhole assembly 20are removed from non-producing wellbore 10A with a substantially commondiameter 18 extending from the surface 14 to the top of the reservoir 30of well 12. After the non-producing borehole 10A is drilled, amonodiameter producing borehole 10B is drilled from the reservoirbarrier 16 and across or through the reservoir 30 to the bottom of thewell 15. It should be appreciated that although FIGS. 9A-G and 3illustrate a vertical well, the well may be on shore or offshore and maybe a new borehole, a vertical borehole, a straight borehole, an extendedreach borehole, extending an existing borehole, a sidetracked borehole,a horizontal well, a deviated borehole, a multi-lateral borehole, orother type of borehole for drilling and completing one or moreproduction zones.

FIGS. 3 and 9A-G illustrate examples of the various stages of drillingof a monodiameter wellbore 10 using a preferred embodiment of thepresent invention. Referring particularly to FIG. 9A, a conductor casing38 for supporting a wellhead 40 is installed into the earth's surface 14such as by drilling, or in the case of a subsea well such as by jettinginto the sea floor. Downhole assembly 20 on work string 22 drills aninitial section 46 of borehole 10A with drilling fluid 68 passingthrough the work string to provide power to mud motor 26 and to removecuttings up the annulus 42 formed by work string 22 and borehole wall44. The drilling mud motor 26 in turn powers the full drift bit 24producing a uniform diameter borehole 48. The bit may or may not beenergy balanced. The first section 46 of borehole 12 is drilled down toand through a formation barrier 50 using drilling fluid 68. Certaincharacteristics of the drilling fluids support drilling the monodiameterwellbore as hereinafter discussed.

Formation barrier 50 may be any change in the formation. Shale is atypical formation barrier dividing different lithologies, pressure zonesor equivalent circulating density (ECD) zones. Once the drilling reachesone of these types of barriers, then the borehole is cased either withchemical casing, expandable casing or a combination thereof.

In most wells, particularly deeper wells that pass through multipleformations, it is necessary to provide support for the formation aroundthe monodiameter non-producing wellbore 10A and to contain formationfluids, earthen materials or solids that would otherwise mingle with thedrilling mud and/or the produced fluids. In more permeable formations,it is also necessary to seal the borehole to prevent fluid loss into theformation. Each of these functions can be provided by casing thenon-producing wellbore 10A either by chemical casing or cladding byexpandable casing or cladding casing with normal casing after variouschemical solutions have been used across the formation barrier 50.

Referring now to FIG. 9B, once downhole assembly 20 drills down throughbarrier 50, the arms 52 with rotary cutters 54 on near bit reamer 28 areexpanded to ream borehole section 46 as the near bit reamer 28 isrotated and moved upwardly within section 46 by work string 22. As thenear bit reamer 28 is pulled back up through the previously drilledsection 46, the borehole is back reamed and enlarged to a largerdiameter 58. The reamer 28 also serves other functions such as cleaningthe previously drilled borehole for better and smoother boreholegeometry.

As the borehole is drilled, a chemical casing 60 may be applied to theborehole wall 44. Chemical casing 60 includes chemicals that permeatethe formation around the non-producing wellbore 10A and change themechanical characteristics of the formation. The casing chemicalssolidify in the formation to form chemical casing 60. The solid chemicalcasing 60 seals and adheres to the formation and thus sets up to form abarrier around the borehole wall 44. Depending on the type of chemicalcasing used, solidification can be a function of time and/ortemperature, or can be triggered by contact between the casing chemicalsand liquids or gases in the formation. For example, some chemical casingmixtures solidify upon contact with formation water.

Referring now to FIG. 9C, the chemical casing 60 may support section 46of borehole 10A until the complete borehole 10 is drilled, then the well12 may be cased with other casing, such a metal casing. It is preferredto apply chemical casing 60 during drilling since it provides support tothe formation wall 44 without restricting the diameter of the borehole10 thereby providing a substantially single diameter. See U.S. patentapplication Ser. No. 10/170,400 filed Jun. 13, 2002 and entitled Methodsof Consolidating Formations or Forming Chemical Casing or Both WhileDrilling, now U.S. Pat. No. 6,702,044, hereby incorporated herein byreference.

One embodiment of the chemical casing 60 includes a two-component systemnamely a catalytic base material and a set-up material. The catalyticbase material is inactive until it becomes activated by the set-upmaterial. The catalytic base material is a penetrating material thatpenetrates the formation. Then the set-up material flows in behind thecatalytic base material with the catalytic base material acting as acatalyst for the set-up material causing it to solidify. The catalyticbase material is preferably mixed with the drilling fluids 68 andpermeates into the formation while drilling. The set-up material is thenapplied activating the catalytic base material to form a solid and thechemical casing 60. The set-up material is spotted in the process sothat it permeates into the formation. Upon permeation into theformation, the catalyzed set-up material seals the formation around theborehole wall 44. The chemical casing 60 may permeate the formation tochange the formation mechanical characteristics or it may merely coatthe borehole wall 44 forming a solid annular chemical casing within theborehole 10.

The catalytic base material may be a polymer which serves as a catalystfor the set-up material which may be a resin. Typically chemical casing60 is the combination of a polymer with a resin technology. One polymeris a polyethylene imine (PEI) polymer and one resin is a melamine-typeresin. For example, a melamine-type resin technology when combined withthe PEI polymer will solidify to form a chemical casing. The polymer isapplied first and then the resin is subsequently applied with thepolymer serving as a catalyst for the resin. For example, the PEIpolymer penetrates the formation and acts as a catalyst for the melamineresin.

The resin may be applied in either a liquid or a solid state. There aretwo types of melamine resin, a soluble resin which is a clear liquid andis completely soluble, or a solid which is a particulate material. Theliquid permeates into the formation where the polymer is located and iscatalyzed in the formation to change the mechanical characteristics ofthe formation. It depends upon the property desired for the formation.The particulate builds a wall for the chemical casing 60. If themechanical properties of the formation are to be changed, the resin willbe in the liquid state to permeate the formation. If only a layer is tobe formed around the inside bore hole wall 44, the resin is aparticulate which merely forms a wall. This flexibility allows theformation to be treated as desired depending upon the particularformation.

One preferred method for forming a chemical casing in a well bore forimproving the mechanical strength thereof and provide zonal isolation toprevent fluid flow between zones or formations while drilling the wellbore is as follows. The well bore is drilled with a drilling fluidhaving a pH in the range of from about 6 to about 10, preferably 8. Thedrilling fluid is comprised of water, a water soluble or waterdispersible polymer which is cross-linkable by a thermoset resin andcauses the resin to be hard and tough when cured, a particulate curablesolid thermoset resin, a water soluble thermoset resin, and a delayeddispersible acid catalyst for curing the solid thermoset resin and thewater soluble thermoset resin. The drilling fluid components form afilter cake on the walls of the well bore that cures into a hard andtough cross-linked chemical casing thereon.

The water soluble or dispersible polymer which is cross-linked by athermoset resin is selected from the group consisting of polymerscontaining one or more of hydroxyl, amide, carboxyl and epoxy functionalgroups. Examples of such polymers include, but are not limited to,acrylic latexes, polyvinylalcohol, polyvinylbutyral, polyesters,polyalkylacrylic acids, polyurethanes, acrylamide polymers, proteins,polyols and polysaccharides such as chitosan, hydroxyethylcellulose,carboxymethylhydroxyethylcellulose, water soluble starches, guar gum,xanthan gum, welan gum, carragenan gum and arabic gum. The polymer isincluded in the drilling fluid in an amount in the range of from about0.5% to about 20% by weight of water in the drilling fluid, morepreferably in an amount in the range of from about 1% to about 10% byweight of water and most preferably in an amount of about 3%.

As mentioned above, the particulate curable solid thermoset resin has aparticle size in the range from about 50 to about 1000 microns and isselected from particulate solid melamine-formaldehyde type resins,urea-formaldehyde type resins or phenol-formaldehyde type resins, andmore preferably from particulate solid alkyl esters ofmelamine-formaldehyde resins and particulate solid alkyl esters ofurea-formaldehyde resins. Of these, the particulate solid alkyl estersof melamine-formaldehyde resins are preferred. The particulate curablesolid thermoset resin used is included in the drilling fluid in thegeneral amount in the range from about 5% to about 50% by weight ofwater in the drilling fluid, more preferably in an amount in the rangefrom about 10% to about 30% by weight of water and most preferably in anamount of about 15%.

The water soluble thermoset resin is selected from water solublemelamine-formaldehyde type resins, urea-formaldehyde type resins orphenol-formaldehyde type resins, and more preferably from water solublealkyl ethers of melamine-formaldehyde resins and water soluble alkylethers of urea-formaldehyde resins. Of these, water soluble alkyl ethersof melamine-formaldehyde resins are preferred. The water solublethermoset resin used is included in the drilling fluid in an amount inthe range from about 5% to about 80% by weight of water in the drillingfluid, more preferably in an amount in the range from about 20% to about70% by weight of water and most preferably in an amount of about 50%.

The acid in the delayed dispersible acid catalyst is an organic orinorganic acid selected from the group consisting of p-toluene sulfonicacid, dinonylnaphthalene sulfonic acid, dodecyl benzene sulfonic acid,oxalic acid, maleic acid, hexamic acid, a copolymer of phthalic andacrylic acid, trifluoromethane sulfonic acid, phosphoric acid, sulfuricacid, hydrochloric acid, sulfamic acid and ammonium salts that produceacids when dissolved in water. Of these, ammonium chloride is preferred.The acid in the delayed acid utilized is included in the drilling fluidin a general amount in the range of from about 0.5% to about 8% byweight of thermoset resin in the drilling fluid, more preferably in anamount in the range of from about 1% to about 6% by weight of resin andmost preferably in an amount of about 4%.

The acid in the delayed dispersible acid catalyst can be delayed usingvarious techniques known to those skilled in the art. A preferredtechnique for controlling the release of the acid catalyst utilized isto cause the acid to be absorbed into a particulate porous solidmaterial whereby the acid is encapsulated. When the encapsulated acid iscombined with the drilling fluid, it is slowly released into thedrilling fluid. While a variety of porous solid materials can beutilized, particularly suitable such materials are inorganic poroussolid materials which remain dry and free flowing after absorbing aliquid chemical additive therein. Examples of such porous solidmaterials include, but are not limited to, metal oxides, e.g., silicaand alumina; metal salts of alumina-silicates, e.g., zeolites, clays andhydrotalcites; and others. Of the various particulate porous solidmaterials that can be used, particulate porous silica is preferred withprecipitated silica being the most preferred.

The delayed release of a liquid chemical additive, absorbed inparticulate porous precipitated silica, is by osmosis whereby theencapsulated liquid chemical diffuses through the porous solid materialas a result of it being at a higher concentration within the porousmaterial than its concentration in the liquid fluid outside the porousmaterial. In order to further delay the release of a liquid chemicaladditive, the porous precipitated silica can be coated with a slowlysoluble coating. Examples of suitable slowly soluble materials which canbe used include, but are not limited to, EDPM rubber,polyvinyldichloride (PVDC), nylon, waxes, polyurethanes, cross-linkedpartially hydrolyzed acrylics and the like. A more detailed descriptionof the encapsulating techniques described above is set forth in U.S.Pat. No. 6,209,646 issued on Apr. 3, 2001 to Reddy et al., thedisclosure of which is incorporated herein by reference thereto.

In order to strengthen the chemical casing formed in the well bore, oneor more insoluble reinforcing materials can be included in the drillingfluid. The reinforcing materials become a part of the filter cakedeposited on the walls of the well bore that cures into a hard and toughcasing thereon. The presence of the reinforcing materials in the strong,hard and tough chemical casing provides additional strength to thechemical casing. The insoluble reinforcing materials which can beutilized include, but are not limited to, carbon fibers, glass fibers,mineral fibers, cellulose fibers, silica, zeolite, alumina, calciumsulfate hemihydrate, acrylic latexes, polyol-polyesters and polyvinylbutyral. Of these, fibrous materials or calcium sulfate hemihydrate arepreferred. When used, the reinforcing material is included in thedrilling fluid in an amount in the range of from about 2% to about 25%by weight of water in the drilling fluid, more preferably in an amountin the range of from about 5% to about 20% by weight of water and mostpreferably in an amount of about 10%.

As mentioned above, the drilling fluid can include other conventionaldrilling fluid additives which are known to those skilled in the art.

A combined method for both consolidating unconsolidated weak zones orformations and for forming a chemical casing in a well bore penetratingthe weak zones or formations to improve the mechanical strength thereofand/or to provide zonal isolation while drilling the well bore is asfollows. A well bore is drilled with a drilling fluid having a pH in therange of from about 6 to about 10, preferably 8. The drilling fluid iscomprised of water, a polymeric cationic catalyst capable of acceptingand donating protons which is adsorbed on the unconsolidated clays,shales, sand stone and the like, a water soluble or dispersible polymerwhich is cross-linked by a thermoset resin and causes the resin to behard and tough when cured, a particulate curable solid thermoset resin,a water soluble thermoset resin and a delayed dispersible acid catalystfor curing the thermoset resins, the drilling fluid forming a filtercake on the walls of the well bore that cures and consolidates theunconsolidated weak zones and formations penetrated by the well bore sothat sloughing is prevented and forms a hard and tough cross-linkedchemical casing on the walls of the well bore.

The polymeric cationic catalyst in the drilling fluid is selected fromthe group consisting of polyethyleneimine,poly(dimethylaminoethylmethacrylate) andpoly(dimethylaminopropylmethacrylate). Of these, polyethyleneimine ispreferred. The polymeric cationic catalyst is included in the drillingfluid in an amount in the range of from about 1% to about 15% by weightof water in the drilling fluid, more preferably in an amount in therange of from about 2% to about 10% by weight of water and mostpreferably in an amount of about 6%.

The water soluble or dispersible polymer which is cross-linked by athermoset resin utilized in the drilling fluid is selected from polymerscontaining one or more of hydroxyl, amide, carboxyl and epoxy functionalgroups. Examples of such polymers include, but are not limited to,acrylic latexes, polyvinylalcohol, polyvinylbutyral, polyesters,polyalkylacrylic acids, polyurethanes, acrylamide polymers, proteins,polyols and polysaccharides such as chitosan, hydroxyethylcellulose,carboxymethylhydroxyethylcellulose, water soluble starches, guar gum,xanthan gum, welan gum, carragenan gum and arabic gum. Of these,polysaccharides are preferred. The water soluble or dispersible polymerwhich is cross-linked by a thermoset resin is generally present in thedrilling fluid in an amount in the range of from about 0.5% to about 20%by weight of water in the drilling fluid, more preferably in an amountin the range of from about 1% to about 10% by weight of water and mostpreferably in an amount of about 3%.

The particulate curable solid thermoset resin, which preferably has aparticle size in the range of from about 50 to about 1000 microns, isselected from particulate solid melamine-formaldehyde type resins,urea-formaldehyde type resins or phenol-formaldehyde resins, and morepreferably from particulate solid alkyl ethers of melamine-formaldehyderesins and particulate solid alkyl ethers of urea-formaldehyde typeresins. Of these, particulate solid alkyl ethers ofmelamine-formaldehyde resins are preferred. The particulate curablesolid thermoset resin is generally included in the drilling fluid in anamount in the range of from about 5% to about 50% by weight of water inthe drilling fluid, more preferably in an amount in the range of fromabout 10% to about 30% by weight of water and most preferably in anamount of about 15%.

The water soluble thermoset resin is selected from the group consistingof water soluble alkyl ethers of melamine-formaldehyde resins, watersoluble alkyl ethers of urea-formaldehyde resins and water solublephenol-formaldehyde type resins. Of these, a water soluble alkyl etherof melamine-formaldehyde resin is preferred. The water soluble thermosetresin is included in the drilling fluid in an amount in the range offrom about 5% to about 80% by weight of water in the drilling fluid,more preferably in an amount in the range of from about 20% to about 70%by weight of water and most preferably in an amount of about 50%.

The acid in such delayed acid catalyst in such drilling fluid is anorganic or inorganic acid selected from the group consisting ofp-toluene sulfonic acid, dinonylnaphthalene sulfonic acid, dodecylbenzene sulfonic acid, oxalic acid, maleic acid, hexamic acid, acopolymer of phthalic and acrylic acid, trifluoromethane sulfonic acid,phosphoric acid, sulfuric acid, hydrochloric acid, sulfamic acid andammonium salts that produce acids when dissolved in water. Of these,ammonium chloride acid is preferred. The acid in the delayed acidcatalyst utilized is generally present in the drilling fluid in anamount in the range of from about 0.5% to about 8% by weight of thethermoset resin in the drilling fluid, more preferably in an amount inthe range of from about 1% to about 6% by weight of resin and mostpreferably in an amount of about 4%.

The drilling fluid can optionally include an insoluble chemical casingreinforcing material selected from the group consisting of carbonfibers, glass fibers, mineral fibers, cellulose fibers, silica, zeolite,alumina, calcium sulfate hemihydrate, acrylic latexes, polyol-polyestersand polyvinyl butyral. Of these, fibrous materials or calcium sulfatehemihydrate are preferred. When used, the insoluble reinforcing materialis generally present in the drilling fluid in an amount in the range offrom about 2% to about 25% by weight of water in the drilling fluid,more preferably in an amount in the range of from about 5% to about 20%by weight of water and most preferably in an amount of about 10%.

As mentioned above, the drilling fluid can also include conventionaladditives known to those skilled in the art.

Another method of consolidating unconsolidated weak zones or formationsand forming a chemical casing in a well bore penetrating the weak zonesor formations to improve the mechanical strength of the well bore and/orto provide zonal isolation while drilling the well bore is comprised ofthe steps of: (a) drilling the well bore with a drilling fluid having apH in the range of from about 6 to about 10, preferably 8, and comprisedof water, a polymeric cationic catalyst capable of accepting anddonating protons which is adsorbed on said unconsolidated clays, shales,sand stone and the like, a particulate curable solid thermoset resin anda delayed acid catalyst for curing the solid resin, the drilling fluidforming a filter cake on the walls of the well bore that cures andconsolidates the unconsolidated weak zones and formations penetrated bythe well bore so that sloughing is prevented; and (b) contacting thewell bore with a treating fluid comprised of water, a water soluble ordispersible polymer which is cross-linkable by a thermoset resin andcausing the resin to be hard and tough when cured and a water soluble ordispersible thermoset resin, the treating fluid components depositing onthe filter cake formed in step (a) and the thermoset resins curing intoa hard and tough cross-linked chemical casing on the walls of the wellbore.

The components in the drilling fluid and the treating fluid are the sameas the components described above in connection with the precedingmethod.

The polymeric cationic catalyst is generally present in the drillingfluid in an amount in the range of from about 2% to about 25% by weightof water in the drilling fluid, more preferably in an amount in therange of from about 5% to about 20% by weight of water and mostpreferably in an amount of about 10%.

The particulate curable solid thermoset resin is generally present inthe drilling fluid in an amount in the range of from about 5% to about50% by weight of water in the drilling fluid, more preferably in anamount in the range of from about 10% to about 30% by weight of waterand most preferably in an amount of about 15%.

The acid in the delayed acid catalyst is generally present in thedrilling fluid in an amount in the range of from about 0.5% to about 8%by weight of the thermoset resin in the drilling fluid, more preferablyin an amount in the range of from about 1% to about 6% by weight ofwater and most preferably in an amount of about 4%.

The water soluble or dispersible polymer which is cross-linkable by athermoset resin is generally present in the treating fluid in an amountin the range of from about 0.5% to about 20% by weight of water in thetreating fluid, more preferably in an amount in the range of from about1% to about 10% by weight of water and most preferably in an amount ofabout 3%.

The water soluble or dispersible thermoset resin is generally present inthe treating fluid in an amount in the range of from about 5% to about80% by weight of water in the drilling fluid, more preferably in anamount in the range of from about 20% to about 70% by weight of waterand most preferably in an amount of about 50%.

The drilling fluid can optionally include a reinforcing material tostrengthen the chemical casing as described above in connection with thepreceding method. When used, the reinforcing material is generallyincluded in the drilling fluid in an amount in the range of from about5% to about 50%, more preferably in an amount in the range of from about10% to about 30% by weight of water and most preferably in an amount ofabout 15%.

As mentioned, the drilling fluid can also include conventional additivesknown to those skilled in the art.

Other preferred compositions and methods are described in U.S. patentapplication Ser. No. 10/170,400 filed Jun. 13, 2002 and entitled Methodsof Consolidating Formations or Forming Chemical Casing or Both WhileDrilling, now U.S. Pat. No. 6,702,044, hereby incorporated herein byreference.

If the formations can support themselves, then back reaming or applyingthe chemical casing may not be necessary.

The borehole is drilled from the top of the well to as far as possiblemonitoring the ECD and fracture gradient window band. If possible, theborehole is drilled across sections of the non-producing area that hasdifferent formations, pressure zones, and ECD measurements. If the ECDsand fracture gradients window narrow or other parameters indicate theremight be the potential of the borehole becoming unstable, then chemicalcasing or expandable casing may be utilized to support the borehole. Ifat all possible, the borehole is drilled from surface to reservoirbarrier.

It should be appreciated that the formulation of the chemical casing mayvary with the type of formation through which the borehole is extending.Thus each section of the borehole, as it is chemically cased, may have adifferent chemical casing formulation formulated for that formationsection.

Resin and polymer technology are disclosed in U.S. Pat. Nos. 4,664,713;4,773,481; 4,799,550; 5,181,568; 5,146,986; 5,304,620; 5,335,726;6,176,315, and 6,271,181, all hereby incorporated herein by reference.Other chemicals include formation stabilization agents such as fibrousmaterials. Chemical casing may also include liquefied metallic casing.

The chemical casing 60 may be applied using various methods. Withrespect to FIGS. 3 and 9A-G, the catalytic base material is mixed inwith the drilling fluids 68. As the SLICKBORE extended gauge bit 24 orrotary steerable extended gauge bit on downhole assembly 20 drills theinitial section 46 of borehole 10A, the modified drilling fluid 68 withcatalytic base material passes through the work string 22 and throughthe bit nozzles. The catalytic base material penetrates the formationsurrounding borehole wall 44. A polymer catalytic base materialpermeates the formation best in a low water loss mud system while theborehole is being drilled.

Then after the bore hole section 46 has been drilled, the bore holesection 46 is under-reamed, and the set-up material is applied during asweep of the bore hole section. As the borehole is back reamed, theset-up material is applied to the borehole wall 44 as reamer 28 passesupwardly through the borehole 10A. The set-up material, in its fluidform, flows down the flowbore of work string 22 and through nozzles inreamer 28. As the cutter blades on the reamer 28 rotate, the nozzlesspray the borehole wall 44 with set-up material allowing the set-upmaterial to penetrate and extrude into the formation surrounding theborehole wall 44. Fluid pressure forces the set-up material of thechemical casing 60 to flow and permeate into the formation. The set-upmaterial contacts the catalytic base material which acts as a catalystto activate the set-up material causing it to solidify and form chemicalcasing 60. In one embodiment the resin coats the bore hole wall 44 withthe polymer catalyst causing the resin to solidify thereby forming thechemical casing 60.

The set-up material may either be a soluble liquid and depending uponthe application, may be a solid. For example, the application willdepend upon the permeability of the formation material such as shale orsandstone. If a chemical casing layer is to be constructed, the solidparticulate set-up material is used which will coat the formation.However, if the mechanical characteristics of the rock and the formationare to be changed, a soluble set-up material is used. The soluble set-upmaterial permeates and solidifies in the formation thereby changing themechanical characteristics of the formation.

The chemical casing 60 also serves as a sealant to seal off the borehole10A. A preferred chemical casing 60 seals the borehole wall 44 such thateven gases can not penetrate the borehole wall 44.

Although the chemical casing 60 is preferably applied through nozzles innear bit reamer 28, the chemical casing 60 can be applied throughnozzles in the bit. For maximum penetration, it is advantageous to applythe chemical casing 60 through nozzles in a modified near bit reamer 28or a modified under-reamer with the nozzles directed toward the boreholewall to allow for maximum borehole wall penetration. As distinguishedfrom a conventional bit where jets are more hydraulically focuseddownward, the nozzles adjacent the cutters on the reamer 28 orunder-reamer are focused toward the borehole wall 44 thus applying thechemical casing 60 directly into the wall 44. Although it is preferredto direct the application of the chemical casing toward the boreholewall rather than the bottom of the well, it should be appreciated thatthe chemical casing may be applied through the nozzles in aconventional, anti-whirl or energy balanced bit. Chemical casing canalso be applied with a modified brush apparatus, turbulator apparatus orapplicator type device. It should be appreciated that the catalytic basematerial may be mixed with the drilling fluids 68 and then the set-upmaterial selectively applied or not applied to a certain portion of theborehole section being drilled.

Chemical casing provides many advantages. It does not reduce thediameter of the wellbore 10. With chemical casing, the drill string maynot need to be removed from the well while drilling the non-producingwellbore 10A. The casing chemicals may provide such a strong surface onborehole wall 44 that the borehole may be able to be drilled from thesurface 14 to the formation barrier 16 using one string of casing. Thechemical casing 60 can also form a barrier across multiple formations.Chemical casing allows the monodiameter non-producing borehole 10A toextend from the surface 14 to the reservoir barrier 16. A formationcompatible chemical casing can allow the producing borehole 10B toextend through the producing formation 30.

Referring now to FIGS. 9D and 9E, once the chemical casing 60 has beenapplied to section 46 and the borehole back reamed, the downholeassembly 20 need not be pulled completely out of the borehole 10A andmay be lowered back through the chemical cased section 46 to continuedrilling the small diameter 48 borehole for next section 56 of borehole10A, best shown in FIG. 9E. As the next section 56 is drilled, it mayencounter another barrier 62. The back reaming step or chemical casingapplication is then repeated.

Referring now to FIG. 9F, additional borehole sections, such as section66, may be back reamed and chemical cased as required to extendnon-producing wellbore 10A from the surface 14 to the reservoir barrier16. Thus, the steps of drilling with the SLICKBORE bit 24, back reamingwith the near bit reamer 28 or chemical casing application device, andapplying the chemical casing are repeated until borehole 10A reaches thereservoir boundary barrier 16.

Referring now to FIG. 9G, after drilling and back reaming borehole 10A,the monodiameter non-producing wellbore 10A is cased with conventionalcasing 70 extending from the surface 14 to the reservoir barrier 16 andthen cemented into wellbore 10A by flowing cement 72 into the annulus 74formed between casing 70 and wellbore wall 44. Although a metal casing,such as expandable casing, is preferred for casing 70, it should beappreciated that casing 70 may be made of a composite or fiberglass. Theexpandable casing can be expandable composite tubing, expandablemetallic casing tubulars, or expandable metallic coiled tubing.

Further, the casing may be a string of expandable casing which extendsfrom the surface 14 to the reservoir barrier 16. Patents related toexpandable casing include U.S. Pat. Nos. 3,191,677; 3,191,680;4,069,573; 4,976,322; 5,348,095; 5,984,568; and 6,029,748, all herebyincorporated herein by reference, and International Publication WO98/22690. Published applications relating to expandable casing includePublished U.S. Patent Application No. 20020060068 published May 23,2002, now U.S. Pat. No. 6,725,919; Published U.S. Patent Application No.20020060069 published May 23, 2002, now U.S. Pat. No. 6,739,392; andPublished U.S. Patent Application No. 20020060078 published May 23,2002, all hereby incorporated herein by reference. U.S. Pat. No.6,470,966, hereby incorporated herein by reference, is related tomethods and apparatus for expanding expandable casing. Other publishedapplications relating to methods and apparatus for expanding expandablecasing include Published U.S. Patent Application No. 20010045289published Nov. 29, 2001, now U.S. Pat. No. 6,631,760; U.S. PatentApplication No. 20010047866 published Dec. 6, 2001, now U.S. Pat. No.6,561,227; Published U.S. Patent Application No. 20020074130 publishedJun. 20, 2002, now U.S. Pat. No. 6,684,947; Published U.S. PatentApplication No. 20020074134 published Jun. 20, 2002; Published U.S.Patent Application No. 20020084078 published Jul. 4, 2002, now U.S. Pat.No. 6,631,769; Published U.S. Patent Application No. 20020092657published Jul. 18, 2002; Published U.S. Patent Application No.20020096338 published Jul. 25, 2002; Published U.S. Patent ApplicationNo. 20020100593 published Aug. 1, 2002, now U.S. Pat. No. 6,631,759;Published U.S. Patent Application No. 20020100594 published Aug. 1,2002, now U.S. Pat. No. 6,705,395; and Published U.S. Patent ApplicationNo. 20020100595 published Aug. 1, 2002; all hereby incorporated hereinby reference. See also SPE 77612 entitled Reaching Deep ReservoirTargets Using Solid Expandable Tubulars by Rune Gusevik and RandyMerritt dated Sep. 29-Oct. 2, 2002. As discussed in greater detailbelow, in embodiments in which a metal casing is used, it is preferredto use expandable metal casing, in order to avoid any reductions inborehole diameter that would be necessary with conventional metalcasing.

It is preferred that chemical casing 60 be used without metal casingduring the drilling operation until all formation intervals are drilledfrom the surface to the formation barrier and that the chemical casingbe used for production depending upon the formation. In the lowerproduction borehole, chemical casing can be used with or without metalcasing or liner. Chemical casing is used only as a temporary casingwhile drilling the non-producing borehole 10A and a permanent metalcasing is installed in borehole 10A to serve as the production casing.The use of chemical casing 60 allows the monodiameter borehole 10A to bedrilled without the installation of an intermediate metal casing so thata common diameter metal casing 70 can be permanently installed in thewell bore for production after borehole 10A has been completely drilled.Thus the chemical casing 60 achieves the objective of avoiding severalintermediate casing strings while drilling. Conventional intermediatecasing strings cause a reduction in the diameter of the borehole.Chemical casing avoids having to set a metal casing for a section ofborehole to reach the ultimate target formation.

The methods and apparatus described above are directed to drilling thewell in one trip and installing the casing in the well all at one time.Such is particularly applicable to shallow wells, i.e., wellbores lessthan 1000 meters deep. A well only 2,000 or 3,000 feet deep may useconventional drill pipe to drill the well where the well only includesone or two formations. In using a conventional drill pipe, the conceptof using expandable casing may still be used. Also the drill pipe may beexpanded and used for casing.

The non-producing borehole 10A is preferably treated separately from theproducing borehole 10B extending from the reservoir boundary 16 throughthe reservoir producing zone 30. The upper borehole 10A is cased offbefore drilling through the reservoir producing zone 30. The same istrue with respect to barriers 50, 62 in that they are cased off at leastwith chemical casing before drilling further.

The sequential steps for constructing the monodiameter non-producingwellbore 10A will vary due to the numerous geological formations thatmust be penetrated to reach the production zone and the numerousdrilling operations and required equipment that must be used to achievethe well plan for drilling and completing a well. The well constructionsequential process described with respect to FIGS. 9A-G and 3 will varydepending on the circumstances of the well.

For example, regulatory agencies may require that the non-producingwellbore 10A be supported by metal casing as the borehole is beingformed for the wellbore 10A, such as where the well is a deep well orwhere the borehole passes through several different formations or wherethe borehole passes through pay zones having different pressures orwhere the borehole passes through unstable formations, tectonic activezones, or a combination thereof. Such occurrences are more likely tooccur in deeper formations where the wellbore will extend throughseveral different formations. In such occurrences, the borehole beingformed for the monodiameter well may need to be cased with metal casingas the drilling of the borehole progresses, as is hereinafter described.

It should be appreciated that the well may be drilled using expandabledrill pipe. The drill pipe may be jointed pipe or coiled tubing.Cementing can be done conventionally down the drill pipe and back upthrough the annulus or cementing can be done by circulating down theannulus between the formation borehole and drill pipe and back up theflowbore of the drill pipe. The drill pipe can then be expanded. Thebottomhole assembly is removed from the drill pipe either by snubbingpipe, coil tubing or wireline. The bottomhole assembly can also bepermanently disposed at the bottom of the well and be cemented in thewell. The drill pipe then serves as the casing. See U.S. patentapplication Ser. No. 10/262,136 filed Oct. 1, 2002 and entitledApparatus and Methods for Installing Casing in a Borehole, herebyincorporated herein by reference.

Referring now to FIG. 12, an alternative embodiment to that describedwith respect to FIGS. 3 and 9A-G, includes mixing the drilling fluid andchemical casing together into one system such that the drillingfluid/chemical casing mixture is used for drilling the borehole whilesimultaneously chemically casing the borehole. The drilling assemblyconsisting of a SLICKBORE and extended gauge bit is used with thedrilling fluid/chemical casing composite fluid to achieve boreholequality for the monodiameter wellbore. The near bit reamer may or maynot be present in the bottomhole assembly as it can be used in helpingto achieve a smooth borehole and get the composite fluid mix deeper intothe borehole. It should be appreciated that a SLICKBORE bit and near bitreamer may be used together to simultaneously drill and ream theborehole as the drilling assembly forms borehole 10A.

The components of the chemical casing 60 are mixed with the drillingfluids 68 passing down the flowbore of the work string 22. The drillingfluid containing the casing chemicals 60 passes through the bit 86 andup the annulus 42 formed between the work string 22 and borehole wall44.

The chemicals in the chemical casing 60 solidify while drilling and thusavoid having to stop drilling or raise the downhole assembly 20 and workstring 22 in the borehole 10A. Thus, drilling and casing are acontinuous process. This continuous process of casing while drilling ispreferably performed for the entire length of the non-producing borehole10A from the surface 14 to the top of the reservoir barrier 16 in onetrip into the well 12. Alternatively, the casing while drilling can beperformed for a plurality of geological formations or it can beperformed from the top of the well to target depth. Various chemicalcasing/drilling fluid composite systems can be applied during thedrilling process of one wellbore with the chemical casing/drilling fluidcomposite system being adapted to the different formations through whichthe borehole is drilled.

The casing chemical 60 mixed with the drilling fluid 68 permeates theformation wall 44 surrounding the borehole 10A to chemically case theborehole 10A while drilling. The drilling fluid/chemical casingcombination includes a glue composition which adheres or seals togetherthe material making up the borehole wall 44 to provide structuralsupport for the borehole wall 44. It is differentiated from otherdrilling fluids because conventional drilling fluids do not penetratethe formation and merely form a filter cake on the borehole wall 44which peels and flakes off in a short time period. Composite chemicalcasing/drilling fluid will support and coat the borehole for a longerperiod of time than conventional drilling fluids. The casing chemical 60also includes a borehole sealant which seals against casing leaks andpenetrates into the formation around the earthen wall 44 to seal theformation.

An alternative embodiment to the combination of drilling fluids andchemical casing includes using the chemical casing as the drilling fluidsuch that the chemical casing, in its fluid form, is used for drillingthe borehole while chemically casing the borehole. The chemical casingperforms the functions of conventional drilling mud, such as cooling thebit and removing the cuttings. It should be appreciated that thisembodiment also includes a bit drilling with a drilling fluids systemthat can stabilize the formation, i.e., the borehole wall 44.

Rather than applying the chemical casing while drilling, anotheralternative preferred method for chemically casing a monodiameterwellbore includes stopping the drilling after completing the drilling ofa borehole section and applying chemical casing.

There are several techniques for applying the chemical casing 60. Onetechnique includes pumping the catalytic base material down the annulus42 formed by the drill string and bore hole wall with the set-upmaterial being pumped down the flowbore of the drill string 22 and thenmixed with the catalytic base material as the drill string 22 is raisedin the borehole 10A and injected into the formation. The chemical casingmay also be applied by first flowing the catalytic base material downthe flow bore of the drill string 22 and then up around the annulus 42followed by the set-up material which then permeates the formation andis activated by the catalytic base material.

Another technique of applying the chemical casing involves circulatingthe catalytic base material down the borehole and drill pipe annulus andreturning it back through the drill pipe/bit bore. Pressure is appliedand the material actually squeezed into the formation.

Application of the composite drilling fluid/chemical casing and singularcomposites can be applied to the formation through devices whichpromotes the fluids to deeply penetrate the borehole formation wallusing drilling “squeeze” devices.

Referring now to FIGS. 13A-13E, there is shown a still another preferredembodiment of the present invention. In this preferred embodiment,expandable casing 90 is used to case the borehole 10 rather thanchemical casing. Although the non-producing wellbore 10A may becompletely formed and then cased with expandable casing 90,alternatively each section of the borehole for non-producing wellbore10A, such as borehole sections 46, 56, 66 shown in FIG. 13E, may becased with expandable casing 90 after it has been drilled until thewellbore 10A has been completely drilled and cased with expandablecasing 90. No chemical casing is applied in this embodiment. If largewash outs do occur during the drilling, it may be necessary to fill inthe borehole walls prior to casing the borehole. A settable spotmaterial may be spotted in the washed out areas and the expanded casingapplied over it.

Since the chemical casing 60 is not used, it is preferred to use theSLICKBORE extended gauge bit or rotary steerable extended gauge bitcombination and/or near bit reamer to insure that the borehole hassufficient quality for setting the expandable casing

If the entire borehole 10A is to be drilled before it is cased, theexpandable casing 90 is installed from the surface 14 to the reservoirbarrier 16 of the well all at one time. Also, the downhole assembly 82of FIG. 12 may be used to drill borehole 10A with downhole motor 84 andstandard full bit 86. Thus the back reaming step of the embodiment ofFIGS. 9A-G and 3 is no longer necessary, but can be performed. FIG. 13Ashows borehole section 46 of borehole 10A having been drilled using astandard full bit 86.

However, preferably expandable casing 90 can be installed in stageswhere a section of expandable casing is installed after each section ofborehole 10A has been drilled. Where expandable casing 90 is installedin sections, the bit must pass through the previously cased section ofborehole 10A and a full standard sized bit, such as bit 86, which hadbeen used to drill the previous casing borehole, cannot be used since itwill not pass through the previously installed section of expandablecasing. Thus it is preferred to use a drilling assembly which includesovergauge hole drilling, such as a bi-center bit or a bit with wingedreamer or a bit with an underreamer, each of which will pass through thepreviously installed section of expandable casing to then drill the samediameter borehole below the previously cased section of the borehole10A.

While chemical casing is the minimum sealing mechanism by which thenon-producing section 10A can be sealed prior to drilling the reservoirsection, it is preferred that the upper borehole has been contained byone of the following: conventional casing, expandable casing, compositecasing, expandable composite casing, coiled tubing or expandable coiledtubing. The bottomhole assembly of FIG. 9A may be used.

As distinguished from the method of FIGS. 3 and 9A-G, borehole section46 is preferably cased with metal casing before the next boreholesection 56 is drilled. FIG. 13A shows an expanded upper section 92 ofexpandable casing 90 installed within borehole section 46 ofnon-producing wellbore 10A.

It should be appreciated that the uppermost section of casing inborehole 10A may be a string of conventional casing that requires noexpansion except any overlapped portion with a next casing 94. The firstcasing string may be conventional casing that has been cemented in placewithin the borehole using conventional cement. The cement 108 in thebottom of the initial string of casing is drilled out and a boreholewith the same diameter is further drilled into the well. A section ofexpandable casing 90 is then installed in the newly drilled borehole bypassing that casing through the upper length of conventional casing.

The expandable casing 90 is cemented into place within wellbore 10A. Ifthe expandable casing 90 is installed from the surface 14 to thereservoir barrier 16 of the well all at one time, then the entire casingstring is cemented at one time. If the casing 90 is installed in stageswhere a section of expandable casing is installed after a length ofborehole 10A is drilled, then each section of expandable casing 90 willbe cemented after it has been installed in the newly drilled section ofborehole. However, when certain sections of the borehole 10A must besupported as the borehole is drilled, then the expandable casing 90 isinstalled in sections to stabilize the borehole wall 44 as sections ofborehole 10A are drilled.

Referring now to FIG. 13B, an additional borehole section 56 of borehole10A is drilled. After borehole section 56 has been drilled, a nextsection 94 of unexpanded expandable casing is then run through uppercasing string 92 and is shown in the process of being installed inborehole section 56. Regular casing may be used and expanded as theexpandable casing 90. The inside diameter 98 of expanded upper section92 is greater than the outside diameter 102 of unexpanded next section94. Next casing 94 has a diameter 102 which is slightly nominal lessthan the diameter 98 of upper casing 92. The amount of the expansion ofthe casing 90 will depend upon its size and weight. Typically theexpansion is between 10% to 20% of the diameter of the expandable casingdiameter, and preferably 20%. Next section 94 can therefore be loweredthrough the upper section 92 such that preferably there is an overlap 96between the lower end of upper section 92 and the upper end of nextsection 94.

Referring now to FIG. 13C, once the next section 94 is in place as shownin FIG. 13B, a piston, pig, wedge, cone, or plunger 100 on a work string101 is disposed within next casing 94 and is hydraulically actuated andpassed through unexpanded next section 94. As the piston 100 movesthrough the flowbore of next section 94, next section 94 is expanded toan expanded diameter 104 which is substantially the same as the expandeddiameter 98 of expanded upper section 92. The piston 100 may passupwardly from the bottom of the casing 94 or may pass downwardly fromthe top of the casing 94. The casing 90 is expanded along its length asthe piston 100 is pumped through the expandable casing string. Thus eachnew length of expandable casing 90 is expanded such that it has the samediameter as the previous installed length of expandable casing. Thepiston 100 may travel all the way back up to the surface 14 or onlytravel through the expandable casing 90 and then be drilled out.

Piston 100 need not be removed from the expandable casing 90 if it ismade from a composite and can be drilled out. The work string 101 isdisengaged from the piston 100 and a bit is run through the expandablecasing 90 to drill out piston 100. If piston 100 is pushed downwardlythrough the expandable casing 90, piston 100 is made of a composite andthen is drilled out for the next section of borehole to be drilled. Itis possible that piston 100 cannot be removed and thus needs to drill itout. If the piston is a composite, this gives flexibility if the pistongets stuck.

It should be appreciated that expandable casing 90 can be set or run byvarious means such as by using pressure, mechanical, hydraulic,electrical, thermal, and/or cryogenic methods. The running of theexpandable casing 90 may also be enhanced by friction reducing agentsin-situ or coated.

The adjacent overlapped ends of sections 92, 94 are cladded together bya sealant. When the next section 94 of expandable casing 90 is run intothe well 12, the overlapping portion of section 94 includes a sealant95, best shown in FIG. 13D, around the upper end of the new section 94of expandable casing 90. When the new section 94 is expanded and theoverlapping portion of section 94 is expanded outward, the sealant 95 isactivated to seal the cladded portion. It should be appreciated that asealant is not always used.

Referring now to FIG. 13D, overlap 96 is enlarged. The upper end of nextcasing section 94 is affixed to the lower end of upper casing section 92by the expansion of the upper end of next casing section 94 inside ofthe lower end of upper casing section 92. As the piston 100 passesthrough overlap 96, both the lower end of previously expanded casingsection 92 and the upper end of next casing section 94 are expanded suchthat overlap 96 also has a diameter common to that of expanded sections92, 94. The overlap 96 between sections 92, 94 of expandable casing 90is flattened out to reduce any restriction in diameter between thesections 92, 94 of expandable casing 90 such that the two sections ofexpandable casing 92, 94 are substantially same inner diameter.Preferably the sections 92, 94 of expanded casing 90 each have an insidediameter which is within a couple of millimeters of the common diameterof the over length of casing 90. Special attention is paid to the overall tensile strength of the casing, the overall loading of the casing,and the potential casing wear that the casing must withstand during thewell construction process.

The annulus 106 between the new section 94 of expandable casing 90 andborehole wall 44 is more narrow than in conventional wells. The annulus106 is preferably at least one inch and no more than 3 inches. It ispreferred to have at least a one inch clearance to allow an adequateflowpath for the cement 108. Cement 108 is pumped down through theflowbore of the expandable casing 90 from its upper end and then aroundits lower terminal end and up the narrow annulus 106. The cement 108then is pumped into the annulus 106 very slowly. The cement 108preferably includes more sealant than regular cement. In the initialsection of expandable casing 92, any fluid in advance of the cement 108will be pushed up through the annulus 106 and back to the surface 14.The cementing can be done in the reverse direction as well. If the uppersection 92 of expandable casing 90 has already been cemented in place,the new section 94 is cemented in place by causing the new cement toforce any column of drilling fluids in the annulus to pass between theoverlapped portions of the casing 92, 94 (before expansion and cladding)and/or be forced out into the formation around the borehole wall 44. Thecementing can also occur after all sections of expandable casing 90 havebeen installed.

To minimize the diameter of non-producing wellbore 10A to be drilled, aminimal clearance, such as one inch, is provided for the annulus 106formed between expandable casing 90 and the borehole wall 44 of thewellbore 10A. Therefore it is preferred to use a resilient polymer,resilient polymeric cement, or foam cement to cement casing 90.Compositions suitable for use in this manner are disclosed in U.S.patent application Ser. No. 10/006,109 filed Dec. 4, 2001 entitledResilient Cement, now U.S. Pat. No. 6,668,928, hereby incorporatedherein by reference and U.S. patent application Ser. No. 10/177,568filed Jun. 21, 2002 entitled Methods of Sealing Expandable Pipe in Wellbores and Sealing Compositions, now U.S. Pat. No. 6,722,433, herebyincorporated herein by reference. Also see U.S. Pat. Nos. 5,873,413;5,875,844; 5,957,204; 6,006,835; 6,069,117; 6,244,344; all herebyincorporated herein by reference.

Other patents relating to expandable casing and chemical casing includeU.S. Pat. Nos. 4,716,965; 5,366,012; 5,667,011; 5,787,984; 5,791,416;and 6,085,838, all hereby incorporated herein by reference.

Referring now to FIG. 13E, a section of expandable casing 90, such assections 92, 94, 110, as for example, are installed after a section ofnon-producing borehole 10A, such as borehole sections 46, 56, 66, isdrilled such that expandable casing 90 is installed in stages.Additional sections of borehole are then drilled, such as throughanother barrier 63, with additional lengths of expandable casing 90installed, expanded and affixed to the expandable casing section aboveit. This is repeated until the non-producing borehole 10A is completelycased with expandable casing 90. The resulting borehole hassubstantially the same size diameter throughout its length so as toprovide a common borehole diameter from the surface 14 to the reservoirbarrier 16.

With drilling the borehole in sections and then casing it in sections,expandable casing 90 is used rather than conventional concentric casingto avoid significantly reducing the inner wellbore usable space forproduction tubing. It is preferred to drill and case the well insections using expandable casing 90 so as to better control drillingthrough the different formations (if it is required from a fracturegradient standpoint) rather than drilling the borehole 10A all at onetime and then installing a expandable casing or conventional casing. Asthe casing 90 is installed one section at a time, the expandable casingprovides mechanical strength to the previously drilled borehole whereotherwise the borehole wall 44 may not hold while attempting to drillthe entire borehole at one time.

Expandable casing 90 not only achieves a substantially common insidediameter but also provides a substantially common outside diameterdisposed in the monodiameter non-producing wellbore 10A. If casing ofdifferent diameters is used to case the monodiameter wellbore 10,different sized boreholes would have to be drilled and thus prevent amonodiameter wellbore. As mentioned above, this is undesirable for avariety of reasons, included the resulting need for a larger volume ofdrilling fluid. Expandable casing 90 allows a constant nominal casingdiameter across multiple formations to produce a monodiameternon-producing wellbore. Thus, expandable casing 90 maintains a constantdiameter when the well must be drilled in sections.

It is desirable to increase the weight of the drilling fluids (mud) asthe borehole is drilled deeper. If the borehole extends through a lowpressure reservoir and ultimately through a high pressure reservoir,drilling fluid will tend to flow into the low pressure reservoir. Thusthe low pressure reservoir must be cased and sealed off to prevent theloss of drilling fluid. For example, This requires the drilling mudweight to be increased from a 8 pound mud to a 9 pound mud or someincreased mud weight. Chemical casing or expandable casing or both mayused in each borehole section to isolate and seal off low or highpressure formations. Once the casing is set across the upper or lowerpressure formation, then the drilling mud, such as a 8 or 9 pounddrilling mud, can be increased in density to a 10 or 14 pound drillingmud to put more pressure on the high pressure formation. The extra mudweight prevents any blowout of the higher pressure formation. Theobjective is to maintain borehole stability, keeping the formationintact and not falling in or fracturing.

Additional description of expandable casing in a monodiameter well maybe found in “The Reeled Monodiameter Well,” by Pointing, Betts,Bijleveld, and Al-Rawahi of Shell International, SPE 54508 May 25-6,1999 and in “Towards a Mono-Diameter Well,” by Benzie, Burge, and Dobsonof e2 TECH Ltd, SPE 65184 Oct. 24-5, 2000.

Referring now to FIG. 14, chemical casing 60 may be used in combinationwith expandable casing 90. In one embodiment, the chemical casing 60 isapplied as described with respect to FIGS. 9A-G and 3. Using downholeassembly 20 with SLICKBORE bit 24, downhole motor 26, and near bitreamer 28, the SLICKBORE bit 24 drills an initial section 46 of borehole10A with a drilling fluid 68, modified to include a catalytic basematerial for the set-up material of the chemical casing, passing throughthe work string to provide power to mud motor 26 and to remove cuttingsup the annulus 42 formed by work string 22 and borehole wall 44. Thedrilling mud motor 26 in turn powers the SLICKBORE bit 24. The SLICKBOREbit 24 produces a small diameter borehole 48. The first section 46 ofborehole 12 is drilled down to a formation barrier 50 using the modifieddrilling fluids (mud) passing through the mud motor 26 and bit 24.

Once downhole assembly 20 drills down through barrier 50, the arms 52with cutters 54 on near bit reamer 28 are expanded to ream the boreholeas the near bit reamer 28 is rotated and moved upwardly within thepreviously drilled non-producing borehole section 46 by work string 22thereby back reaming and enlarging the borehole to a larger diameter 58.The reamer 28 also cleans and smooths the wall of the previously drilledborehole.

As the borehole is back reamed, chemical casing 60 is applied to theborehole wall 44 as reamer 28 passes upwardly through the borehole 10A.Chemical casing 60, in its fluid form, flows down the flowbore of workstring 22 and through nozzles in reamer 28 to spray the borehole wall 44with chemical casing 60 allowing the chemical casing 60 to penetrate andseal the earthen wall 44. Pressure forces the chemicals of the chemicalcasing 60 to flow and permeate into the formation surrounding theborehole wall 44. Thus, as the borehole is reamed and enlarged, thechemical casing 60 is applied while reaming. The solid chemical casing60 seals and adheres to the formation and thus sets up to form a barrieraround the borehole wall 44.

The chemical casing 60 supports section 46 of borehole 10A until asection of expandable casing 90 is installed in borehole section 46 suchthat the borehole 10A is cased both with chemical casing 60 andexpandable casing 90. After section 92 is installed and cemented, thenext section 56 of borehole 10A is drilled, back reamed and chemicalcasing applied. A next section 94 of expandable casing is installed, asdescribed with respect to the embodiment shown in FIGS. 13A-E.Alternatively each section of the borehole for non-producing wellbore10A, such as sections 46, 56, 66 shown in FIG. 13E, is drilled, backreamed and chemically cased and then a section of expandable casing 90,such as sections 92, 94, 110, installed until the wellbore 10A has beencompletely drilled and cased with chemical casing 60 and expandablecasing 90.

Another preferred embodiment includes applying the chemical casing insections for the non-producing wellbore 10A and then installing theexpandable casing in one operation across all the sections.

Thus, one method of constructing a land based monodiameter wellbore inaccordance with the present invention includes setting conductor pipe,setting structural casing and cementing the casing in place, drillingthe formations utilizing drilling fluids (mud) and chemical casing,running expandable casing and cementing the expandable casing in place,and expanding the casing.

Although the preferred embodiment of FIG. 14 includes the application ofchemical casing 60 during the back reaming of the small borehole drilledby SLICKBORE bit 24, it should be appreciated that the expandable casing60 may be used with the embodiment described with respect to FIG. 3. Theborehole 10 is drilled using a mixture of the drilling mud and chemicalcasing combined into one system such that the borehole is drilled whilebeing chemically cased. Thus the drilling fluid 68 with the chemicalcasing 60 causes the casing chemicals to permeate the formation wall 44surrounding the borehole 10A to case the borehole 10A while drilling.Since the drilling mud 68 is mixed with the chemical casing 60, the backreaming step of the embodiment of FIGS. 9A-H and 3 is no longernecessary but may still be utilized to insure the chemical casing isthoroughly deeply penetrated into the formation.

As described with respect to FIG. 14, a section of expandable casing 90,such as sections 92, 94, 110, as for example, are installed after asection of non-producing borehole 10A, such as sections 46, 56, 66, isdrilled such that expandable casing 90 is installed in stages.Additional lengths of borehole are then drilled with additional sectionsor lengths of expandable casing 90 installed, expanded and affixed tothe casing section above it. This is repeated until the non-producingborehole 10A is completely cased with expandable casing 90. It ispreferred, if the drilling fluid/chemical casing can support theborehole, that the casing be installed as one complete casing stringrather than installing the casing in stages.

An alternative embodiment to the use of expandable casing after drillinga borehole section using a mixture of drilling fluids and chemicalcasing includes using the chemical casing as the drilling fluid suchthat the chemical casing, in its fluid form, is used for drilling theborehole while chemically casing the borehole. The chemical casingperforms the functions of conventional drilling mud, such as cooling thebit and removing the cuttings. It should be appreciated that thisembodiment also includes a bit drilling with a drilling fluids systemthat stabilizes the formation, i.e., the borehole wall 44. As describedwith respect to FIG. 13E, a section of expandable casing 90, such assections 92, 94, 110, as for example, are installed after a section ofnon-producing borehole 10A, such as sections 46, 56, 66, is drilled suchthat expandable casing 90 is installed in stages. Additional lengths ofborehole are then drilled with additional sections or lengths ofexpandable casing 90 installed, expanded and affixed to the casingsection above it. This is repeated until the non-producing borehole 10Ais completely cased with expandable casing 90. It is preferred if thedrilling fluid/chemical casing can support the borehole, that theexpandable casing be installed in one complete casing string rather thaninstalling the casing in stages.

In the previously described embodiments, it should be appreciated thatthe chemical casing 60 may be applied along the entire non-producingborehole 10A, along only one or more of the individual boreholesections, or along only a portion of an individual borehole section.Further it should be appreciated that the formulation of the chemicalcasing 60 may be varied according to the geology of a formationencountered in a borehole section. Thus the application and formulationof the chemical casing 60 is selective and elective for the variousportions of the formation through which the borehole 10 extends.

Further, the selective and elective isolation of the borehole wall maybe performed by various techniques using chemical casing and expandablecasing. For example, a shale formation may be optimally isolated withexpandable casing while a sandstone formation may be optimally isolatedwith chemical casing which can more easily permeate a sandstoneformation. Thus, with both expandable and chemical casing available, aparticular portion of the borehole 10 may be electively and selectivelycased.

One of the advantages of using real time MWD and LWD measurements is toidentify the particular formations through which the slick bore bit 24is drilling in the borehole 10. Thus, once a borehole section is drilledand the borehole is being under-reamed, different chemical casings canbe spotted across the different formations through which the borehole 10extends. Even if the chemical casing 60 is being applied during thedrilling of the borehole 10, the formations through which the borehole10 extends may be known thus allowing the chemical casing formulation tovary as the bit drills through a particular formation. The formulationof the chemical casing 60 can then be varied for each different strataof formation through which the borehole extends 10. For example, oneformation strata may be soft sand, another formation strata may be hardshale, and still another formation strata may be granite, each beingchemically cased with a different chemical casing formulation or casedwith expandable casing or both be chemically cased and cased withexpandable casing.

Chemical casing 60 allows a borehole section to be drilled deeper orlonger than in the prior art before a length of expandable casing needbe installed to support the formation. If an excessive large number ofexpandable casing strings must be installed due to a large number ofcasing intervals, the large number of expandable casing strings willbegin to reduce the borehole diameter. Chemical casing can be appliedwithout tripping out the drill string. In installing the expandablecasing, the borehole must be treated and then the expandable casing set,cemented, and expanded. Expandable casing cannot be installed whiledrilling. Drilling must be stopped and then resumed. Thus, there is asubstantial cost savings in using chemical casing to extend the boreholeinterval. The chemical casing provides a temporary support of theformation so that the length of expandable casing to be installed can bemaximized. Thus, chemical casing allows the borehole to be drilleddeeper before a length of expandable casing has to be set in theborehole.

It should also be appreciated that the chemical casing 60 may not extendthe entire length of the borehole 10. One of the limitations of chemicalcasing is temperature. Once a predetermined temperature is reached,certain chemical casings can no longer be used and expandable casingmust be used. Once the borehole reaches a certain depth where thedown-hole temperature exceeds the limitations of the chemical casing,expandable casing is used. Thus, traditional chemical casing may only beapplied in those borehole sections where conventional intermediatecasing might otherwise be used. Higher temperature rated chemical casingmaterials can be used and applied in higher temperature wellbores.Therefore, typically, the chemical casing extends to the formationbarrier 16.

For example, if the borehole temperature exceeds the limits of thechemical casing prior to reaching the formation barrier 16, the chemicalcasing will stop at the depth where the borehole temperature exceeds thelimits of the chemical casing and the remainder of the borehole, down tothe formation barrier 16, will be cased using a higher rated chemicalcasing or expandable casing if required. A production liner, such as aproduction string, may be set at the formation barrier 16 and extenddown through the target formation. Where the chemical casing is notavailable, only expandable casing may be used.

The number of expandable casing sections which must be installed intothe wellbore is dependent upon having a consolidated formation orconsolidating the formation to prevent sloughing into the wellbore andto prevent fluids from one formation from commingling with fluids inanother formation. It is also preferred to drill as long an interval aspossible to reduce costs. Thus, it is preferred to use chemical casingand chemical solutions to permit the drilling of longer intervals. Inparticular, chemical casing not only may consolidate an unconsolidatedformation but also may provide a hard inner wellbore wall which willprevent the commingling of fluids from adjacent formations and thusallow the drilling of a longer interval and the reduction of the numberof expandable casing sections. One or more chemical casings can reducethe number of expandable casing sections. Thus, where chemical casingwill prevent the commingling of fluid between two formations, additionalsections of expandable casing are avoided. The chemical casingconsolidates and hardens the borehole wall long enough to allow thedrilling of a longer interval before the installations of expandablecasing. The objective is to use one or more chemical casing sections tolengthen the interval required for one expandable casing.

Referring now to FIG. 15, there is shown still another embodiment of thepresent invention. In FIG. 15, the monodiameter wellbore 10 passesthrough a salt formation 180. Regulatory agencies may not allow only onecasing to pass through multiple formations and thus require anadditional casing 182. Regulatory agencies are concerned with thecommingling well fluids from a producing formation with well fluids inanother producing or non-producing formation. They also concerned withmixing salt with a producing formation or commingling hydrocarbons fromtwo different producing formations. Thus, regulatory agencies mayrequire a double barrier to the formations to ensure that the mixing offormations does not occur.

The casing system of FIGS. 13A-E is shown for the well in FIG. 15.Although the expandable casing 90 and the chemical casing 60 formbarriers across multiple formations, a structural casing 182 may be usedto form an additional barrier across the formation. Structural casing iscasing used to support the wellhead and carries the load of thewellhead. It has a thicker wall and provides a stable support frame forthe wellhead whether it be subsea or land operations.

In wells extending through a salt formation, such as in the Gulf ofMexico, the structural casing 182 may be extended from the wellhead 40typically a few hundred feet, to serve as a support for the wellhead.The structural casing 182 may be a conventional casing or an expandablecasing. Further, it is important that the casing 90 maintains itsintegrity. An outer casing may be placed through the salt formation toprotect the primary wellbore casing from salt corrosion and possibledamage.

A drilling template is set on the sea floor 14. Casing is set topenetrate through the mud line, such as conductor casing 38 and iscemented in place. This may be 36 inch diameter pipe. The 13⅜ structuralcasing 182 is then set and cemented in place. Casing strings are thenset across the formation or a drilling hazard zone, such as saltformation 180. The borehole is then drilled utilizing drilling fluidsand/or chemical casing. The expandable casing then is run, cemented inplace, and is expanded. This process is repeated. Finally, the casingstring then is set to the top 16 of the reservoir 30.

The wellbore 10 and borehole for the structural casing 182 may bedrilled with chemical casing and then completed with expandable casing.It is preferred that the structural casing is not expandable. However,the structural casing 182 need not be chemical casing and expandablecasing. The inner casing 90 can be chemical casing and expandablecasing, or it can be conventional or composite casing. The outer casing60 can be expandable casing or conventional casing

Another casing can provide a second barrier across the salt formation180 due to the requirement that the well have at least two pressurebarriers. Although it is an objective of the present invention to limitthe number of casing strings extending into the well, certain formationsmust be closed off, such as salt formation 180, and therefore anadditional barrier may have to be installed.

If, for example, there was a second salt formation between saltformation 180 and reservoir 30, the barrier casing 182 could preferablyextend through both salt formations to close them off from the wellbore10. A liner in the barrier casing 182 could be used to close off a lowersalt formation by hanging the liner adjacent the end of barrier casing182. It is preferable however to extend the barrier casing 182 throughboth formations.

The structural casing can be pile driven or suction driven down ratherthan traditionally drilled. In this case, case and drill operations canbe applied creating this outer casing structure.

In the MONOWELL, formation evaluation occur primarily during thedrilling rather than later. Formation knowledge is maximized at theonset so that an operator can better handle bore-stability issues orcompletion issues. In the upper borehole, the bit should travel theoptimum wellpath. Also, evaluation for designing the optimum completionis done. The bottomhole assembly preferably includes taking pressurewhile drilling, vibrations, tortuosity, lithology characteristics,faulting (fracturing) characteristics, and drilling measurements thatallow the wellpath to be re-evaluated in real-time while drilling. Thisdata is integrated with the reservoir and geomechanics models so thatdecisions can be made that result in the construction of an optimalMONOWELL. These decisions are focused on the following areas: optimumpathway to optimum reservoir recovery; quality borehole; boreholestability; mud management including ECDs; bottomhole assemblyreliability, borehole management (knowledge of where and when to applyborehole-strengthening materials and reservoir completion optimization),formation damage, formation productivity, and other related areas.

Across the completion section, the bottomhole assembly takes on theadditional requirements of defining the reservoir so that an optimumcompletion is executed. Therefore, the reservoir is evaluated from botha petrophysical and productivity viewpoint. For themonodiameter/monobore, the best formation evaluation includesmeasurements using sonic or nuclear magnetic resonance (NMR) toolsbecause they provide information about: porosity, permeability, fluidsidentification; producibility, fluid distribution, oil quality, porepressure, seismic time-depth correlation, gas detection, rock mechanicalproperties, and fault and fracture detection.

A sonic tool is also recommended in the upper borehole 10A becauseborehole stability and mud and cementing casing designs may be improvedby data on the following: pore pressure, seismic time-depth, gasdetection, fault/fracture detection, and rock mechanical properties. Thesonic tool provides the information about when to apply expandablecasing, material for drilling ahead, chemical casing material, and aspecially formulated drilling fluids system for the particular formationdrilled. Across the reservoir, the combination of sonic and nuclearmagnetic measurements allow the following to occur: optimal screen orliner placement across the formation; borehole stability in relation toperforations and longevity of the completion; perforating orientation;stimulation selection (if required); completion design with regard tofuture potential required conformance; and quality of borehole thatcontributes to better completion execution and in the long run betterproduction.

The MONOWELL completion begins with the drilling of the reservoirsection. Optimum well performance and reliability are the primary focus.Ultimately, borehole quality leads to better production. Drilling theborehole with a matched mud motor and bit, and underreaming the hole inthe same trip, allows a smooth wellbore to be achieved with minimumformation damage. The initial bit penetration has the most concentriccutter contact, while the follow-up underream provides a smoothwellbore. The drilling fluid impacts the borehole quality and overallwell productivity. A drilling-completion fluid that basically “seals”the formation minimizes fluid losses, provides a conduit forinstallation of the borehole structural support, and provides effectivewellbore production delivery. These methods lead to better wellboreformation evaluation and borehole support-structure installation,whether used with a conventional liner or expandable liner or screen.

The fluids used while drilling through the lower producing zone protectthe reservoir and minimize fluid losses for maximum well productivity.Washouts are minimized because long-term well productivity, along withformation evaluation, is generally affected. Reservoir drilling fluidssuch as brine fluids, carbonate fluids with in-situ acid breakers, andclay-stabilization fluids stabilize the monobore/monodiameter wellborewith the least formation damage.

The lower producing zone is drilled with real-time formation evaluationso that exact placement of the completion equipment can be modifiedwhile drilling is still ongoing, minimizing downtime associated withreplanning the completion after logging. For example, blank sections andexternal casing packers (ECPs) may be added because of stratigraphy orfluid-contact deviations from what was originally planned. Additionally,potential conformance issues are considered.

The union of the monodiameter and monobore design parameters converge atthe lower producing zone. The monodiameter design strives to reduce thewellbore sizing but the monobore design strives to maximize thereservoir exposure and the well's productivity. Using the expandableliner hanger can allow this union to occur. From the liner hanger towell total depth (TD), expandable liners, expandable screens,traditional liners, traditional screens, other nonmetallic liners orfluid/proppant solutions (i.e. resins) can be used depending on thecurrent and future requirements of the reservoir. The primary objectiveis to simultaneously optimize both the inflow performance and the tubingoutflow performance.

In unconsolidated sandstone formations, expandable screens can providethe greatest uniform reservoir exposure and have reported some of thegreatest benefits. Expandable sand screen development and deploymenthave benefits that include: reduction in spot erosion locations,increased borehole access for interventions, increased borehole for welldeliverability, increased production rates (due to more efficientperforation packing), and more reliable complex horizontal gravelpacking.

If the producing formation is a carbonate, which is a hard rock or ahard sandstone such as one having 0.1 millidarcy, then a monodiameterborehole can be achieved. If, however, the producing formation is anunconsolidated sand, such as one requiring gravel packing, where forexample the formation has 2 darcy, then a chemical casing or internalbreaker drilling/completion fluid and expandable screen may extendacross the formation. This may or may not require perforation. It isalso possible to merely go in and frac pack the producing formation. Italso means that the diameter through the producing formation would bereduced. Multiple screens extending across the producing formationcauses the wellbore to be narrowed through the producing formation.

Chemical casing may be used in the lower borehole extending through theproducing formation so long as it does not permeate or extend too farinto the formation so as to damage the reservoir. It is important toachieve a very tight, low fluid loss across the producing formation. Ifchemical casing or regular cement are used through the lower boreholeextending through the producing formation, then it is to be perforated.

Halliburton has chemicals which solidify the lower borehole wallextending through the producing reservoir and still allow well fluids tobe produced through it. Such chemicals may be placed in the lowerborehole extending through the producing formation without requiringperforation.

One type of chemical is a conductivity enhancer allowing hydrocarbons tobe produced through the lower borehole wall. The conductivity enhancerremains on the borehole wall and then an expandable screen is set acrossthe producing formation. The conductivity enhancer is a different typeof chemical casing such that it consolidates and solidifies theformation but does not require perforation and will allow the productionof fluids through it. The conductivity enhancer is a substitute forchemical casing or cement. One conductivity enhancer includes a calciumcarbonate fluid that has internal breaker stimulants and which is usedwith expandable screens. The conductivity enhancer can be used whiledrilling with a liner or screen and then expanding and leaving the lineror screen in the borehole. Drilling may be conducted through the linerwhich may or may not include a screen on its lower end. Typically theliner is a solid tubular and is perforated to produce the well.

The MONOWELL may be considered for any well because of the benefits ofthe smaller upper support structure and maximum well delivery conduit.Initial completion is achieved with coiled tubing (or wired compositetubing) for possible placement of the tubulars, proppant and screen.While this method is traditionally not used today, using it may generateadditional savings because the larger rig can be released when thereservoir drilling and completion begins. Also, the large rig may bereleased when the initial chemical casing or nested expandable boreholeis installed for the upper borehole. The coiled tubing unit or wiredcomposite tubing may be used to install the tie-back (secondarybarrier).

Referring now to FIG. 16, there is shown a completed well. An expandedcasing 242 is shown cemented at 244 into the monodiameter wellbore 246.A packer 248 is set at the lower end of a completion string 250. Anexpandable liner hanger 251 supports a liner 253 having a plurality ofscreens 255 on its lower end. The drilling fluid has an in-situ breaker.The completion equipment 250 for completing the well includes acompletion string 252 which is fullbore to complete the final deliveryof an optimized well architecture. Depending on the location, safety andenvironmental concerns, as well as governmental regulations and thereservoir, the completion equipment may include fullbore safety valves254, reservoir-pressure monitoring 256, shutoffs 258, fullbore nipples260, measurements, evaluation, and various other devices.

Smart wells are considered for long-term cost reduction by being able tomanage the reservoir at the sandface. Smart wells include sensors andconductors for transmitting to the surface the data and informationmeasured and collected by the sensors. The conductors may be electricalwires, fiber optics, hydraulic, or other type data conductors. Fiberoptics are able to provide data and information to the surface. Forexample, fiber optics may be used to measure downhole temperature andpressure and transmit those measurements to the surface real time forwell control. Smartwells can provide this as well as be able to controlvarious reservoir fluids and zones. Additionally, smart wellinstallation can be integrated with the wired composite coiled tubingfor long-term real-time reservoir dynamic process monitoring andmanagement. See U.S. Pat. No. 6,257,332 issued Jul. 10, 2001 entitledWell Management System, hereby incorporated herein by reference. Moredetails on drilling and completing composite coiled tubing units are setforth hereinafter. Preferably conductors are embedded in the wall of thecomposite coiled tubing to transmit real time data and information tothe surface for analysis and processing. Fiber optics may be preferredsince fiber optics can transmit more data than electrical conductors andhave more data across the entire reservoir interval rather than merelydata at a localized position. Production flows to a floating miniproduction satellite unit 262 having a communications system 264 forsending data and other production information to a central location. Itshould be appreciated that the conductors include electrical, fiberoptics, and any other means by which information or instrument commandscan be delivered. Commands and data transmitted from completion ordrilling devices may be transmitted by acoustic, vibrations, hydraulic,radio frequency, short or broad band, or any other energy mechanism. Forexample, based on the data and information of the sensors, completiondevices may be opened, closed, adjusted or otherwise manipulated bymeans of commands or signals transmitted to the devices through theconductors.

Referring now to FIG. 17, there is shown a MONOWELL 270 having amonodiameter 272 with nested expandable casings 274. The upper boreholehas a plurality of expandable sections. A secondary barrier, in the formof a traditional casing tie-back 284, may be installed within themonodiameter 272. A structural pipe 278 has been installed. A fullboredelivery system 280 with tubing 276 having a full bore safety valve 282is disposed within casing tie-back 284. Mechanical solutions andexpandable liner hanger 286 below a packer 288 are used. For thereservoir, the liner hanger 286 supports a gas tight expandable liner290 with expandable screens 292.

The monodiameter, monobore, and MONOWELL of FIG. 17 are achieved bydrilling and casing one formation section at a time sequentially. Nestedexpandable casings 274 and gas-tight production liners 290 are used forachieving the monodiameter. The nesting of the expandables permits theuse of a second or third-generation semisubmersible where the well isconstructed in a deepwater environment.

Referring now to FIG. 18, other technologies can be used to achieve themonodiameter and monobore in combination or separately from the abovetechnologies. In the system illustrated in FIG. 18, the formations aredrilled and isolated while their mechanical pressure integrity isincreased through chemical processes, such as drill ahead material 238and chemical casing material 236. This allows larger portions of theupper borehole 10A to be drilled. Regular or expandable casing 274 arethen used for the structure of upper borehole 10A. If real-time chemicalapplication methods are used, the system of FIG. 18 will result in fewersteps (i.e. less time) in the upper borehole well-construction process.Across the productive interval 300, drill-in fluids with sealingcapabilities, with or without internal breakers, are used for drillingthe section. If certain zones are not pay zones, but require attentionto allow the next pay zone to be drilled, using a drill ahead material238 to improve the pressure integrity of the formation will help achieveproductive drilling. The reservoir section 300 can be completedopenhole, with expandable screens 292 or expandable tubular liners 290,shown in FIG. 17, or traditional liners to maintain the monodiameteracross the lower producing zone 300. Installing an expandable linerhanger 286 and a short section of expandable tubular 302 in theintersection of the upper borehole 10A and producing zone 300 can helpmaintain the monodiameter and monobore if desired.

If the monodiameter is to be maintained only in the upper wellbore 10A,completion options are open across the lower producing zone 300: fracpacs, gravel packs, cased liners, liner hangers, etc. The intersectionbetween the upper borehole section 10A and lower producing zone 10B caninclude traditional equipment or expandables if desired.

The lower producing zone 10B is preferably drilled with SLICKBORE and/ornear bit reamer or rotary steerable or rotary steerable with long gaugebit, energy balanced bit, or other bit system, full drift bit system, ordisposable bit system. Drill-in fluid is drilling fluid which iscompatible with the formation and is defined as having a minimum of 65%return permeability when tested against formation lithology and actualdrill-in drilling fluid.

It should be appreciated that the lower producing borehole can bedrilled with a compatible drill-in fluid and left openhole; the boreholecan be drilled with drill-in fluid and perforated; the borehole can bedrilled with drill-in fluid, underreamed either going down or up, andthe formation sealed; the borehole can be drilled with drill-in fluidand an expandable screen or expandable composite installed; the boreholecan be drilled with drill-in fluid, sealed and cased using conventionalcasing or expandables (Coil tubing, composites or tubulars) andperforated; the producing interval can be drilled with compatibledrilling fluids (drill-in fluids), reamed with near bit reamer,perforated, stimulated (fractured) and a permanent support set in placesuch as expandables (tubulars or screens), conventional tubulars orscreens, alternating path screens or composite screens; the producinginterval can be drilled using bit and liner combination as drill string,left in hole and expanded or not expanded. The liner may or may not be acomposite, tubular, expandable materials, non-ferrous alloys, ferrousmaterials or nanotechnology materials.

Referring again to FIG. 3, there is shown a particular example of aMONOWELL. A monodiameter producing borehole 10B is drilled from thereservoir barrier 16 and across or through the reservoir 30 to thebottom of the well 15, with temporary sealing, over-balanced,under-balanced or special drilling fluids. In the producing borehole10B, the near bit reamer is preferred because it builds a smoothborehole allowing for a better completion—whether it is an expandablescreen only, liquid screen, some type of stimulation and screen, orperforating and cased borehole. The near bit reamer can be used inapplying a formation compatible fluid for producing through it such as aspecialized drill-in fluid that has internal breakers it can dispersewith time. Drill-in compatible fluid may or may not have the internalbreakers or traditional cement or expandable casing cement. Chemicalsolutions that do not result in deep reservoir damage can be appliedwhile drilling the reservoir as well.

In drilling through the producing formation 30, particularly insandstone, calcium carbonate is used to build a cake wall to hold backthe pressures of the producing formation. The fluid which forms the cakewall may include an encapsulated breaker or a delayed breaker. Thebreakers are completely disbursed in the fluid for the cake wall. Thebreaker is typically an acid. The time release encapsulated acid isreleased over time in the cake wall. The encapsulation dissolvesallowing the acid to allow production from the formation through thecake wall. This avoids or minimizes the need for acidizing theformation. Treatment, such as acidization, often is not effective alongthe entire interval exposed to the producing formation. The internalbreakers are more evenly distributed in the cake wall throughout theproducing interval, such that upon being released, the entire producinginterval is acidized to increase production.

The cement may be liquid chemical casing. If it is dispersed acrossunconsolidated formation, then it may not be cement but fluidscontainment called liquid screens. Liquid screens or a liquid screenwith expandable screens having the same diameter as the upper bore,i.e., monodiameter, can be placed across the reservoir. See thedescription of SANDWEDGE in U.S. Pat. Nos. 5,775,425; 5,787,986;5,833,000; 5,839,510; 5,853,048; 5,871,049; 6,047,772; and 6,209,643,all hereby incorporated herewith by reference.

Producing borehole 10B is, normally, not chemical cased, however it ispossible. Expandable casing with expandable casing cement or traditionalcement and liner may be used. More traditional liners may be suspendedin the lower end of the monodiameter casing and through the lowerproducing zone. However, a chemical casing may be part of the producingzone, initial drilling fluid system or a separate fluid or fluid slurrysystem that can be applied when the lower producing zone is underreamed.A production liner and/or screen 78 may be suspended adjacent the end ofcasing 70 and extend into or through the lower producing borehole 10B.The screen may be expandable or not expandable. Production tubing 80 isinstalled within casing 70, 78 for producing production reservoir 30.The casing 70, 78 and production tubing 80 may be conventional casing orexpandable casing or expandable screen and production tubing. The well12 may be completed by perforating the casing 78 adjacent the producingreservoir 30 with the perforations allowing produced fluids to flow intothe production tubing 80 and flowing to the surface 14 as in well knownin the art. The well does not require being perforated, it may be leftopenhole and screened (expandable or conventional). Only in the case ofthe solid liner (or solid expandables) will perforating be absolutelyrequired.

The lower producing borehole 10B can be drilled with a drill-in linerand cased in place. A drill-in liner is either a part of the drillstring or is mounted on the drill string above the bit. The drillingliner may be the work string. The liner may be mounted just above thebit allowing the bit to be withdrawn through the liner upon completionof drilling the borehole. Where the liner is mounted above the bit, thebit may be disconnected from the drill-in liner and removed by theattachment of an insert mounted on a drill string which is connected tothe bit. The insert with bit are then pulled out of the liner and areremoved and retrieved. The liner can be solid, expandable, screen orexpandable screen. A screen may be used in place of the liner where thescreen has the necessary mechanical strength to withstand the loadsplaced on it due to the drilling operation. The drill-in liner may ormay not consist of removable MWD/LWD and bit. Also, it may or may not becemented in place. The bottom hole assembly includes an MWD and LWD,which may or may not be able to be retrieved out of the bottom holeassembly. The bottom hole assembly may just be left in the borehole as adisposable assembly. A plunger then is lifted in the liner or screen toexpand it outward. It should be appreciated that some other means may beused to expand the liner or screen. In essence the work string on thebottom hole assembly is then used as a liner.

FIG. 3 illustrates a monobore, i.e., a fullbore delivery system. Afullbore production delivery system has a completion tubular with amonodiameter production bore, i.e., the same nominal internal diameterthroughout the inner conduit extending from the surface to the bottom ofthe well. The monobore does not necessarily extend through theproduction casing or may extend down through the casing, liner, orscreen. While a well may have a monodiameter architecture, it may or maynot have a full bore production delivery system. Thus the presentinvention may or may not include a fullbore production delivery system.If the well has both characteristics of a monodiameter casing and afullbore production delivery system, then the well design is called aMONOWELL.

In the monobore completion design, the liner is seen as an extension ofthe tubing. The first requirement for a monobore completion is that itprovides a consistent diameter throughout. In the present embodiment, toachieve the monobore, it is preferred but not necessary that thewellhead and Christmas tree be full bore to provide full access to thereservoir. It is not mandatory. Most monobore wells will not have a fullbore wellhead and Christmas tree. The monobore is defined as onlyextending from the tubing hanger down to the formation barrier. It doesnot have to extend through the Christmas tree and wellhead. Theproduction is full bore if the production tubing is full bore from thetubing hanger to the formation barrier.

The number of completion components and type will vary according tofield and well needs. The gauges for measuring pressure and temperatureand the safety valve are all full bore. The nipple 22 near the bottom ofthe tubing is also full bore. Further, Halliburton has a through borenipple which is full bore. Thus, the present embodiment provides norestrictions in the producing bore from the formation barrier to thesurface. These all are part of the completion tubular string and have aninside diameter common to the entire string. The inside diameter of thecompletion tubulars normally has the same inside relative nominaldiameter. Completion components normally do not have the same relativenominal diameter but are preferred in the monobore.

In one type monodiameter, the upper borehole 10A is cased and then thelower borehole 10B through the producing formation is cased with thelower casing/liner overlapping the lower end of the upper casing andbeing cladded thereto. At the overlap, the cladding increases thethickness of the monodiameter casing due to the overlapping of the twocasing strings. Production tubing extends through the expandable casingin the upper borehole 10A and through the lower borehole 10B through theproducing formation. The casing extending through the producingformation is perforated. In this method, there is no variance betweenthe liner and the production tubing. There is a true monobore.

In another method, instead of cladding a casing string, an expandableliner hanger, suspending an expandable liner, is disposed from the lowerend of the casing extending through the upper borehole 10A. To achievethe monodiameter casing, the liner and liner hanger are expanded. Theexpandable hanger includes a seal bore for receiving the lower end ofthe production tubing. In a second method, the tubing is stabbed intothe top of the liner. A packer is disposed between the tubing and thecasing. The expansion of the liner approximates the outer diameter ofthe previously set casing in the upper borehole 10A but it is not thesame. There is a variance. Thus, in this method, although there are somevariations, they are relatively small and the well may still be termed aMONOWELL because the well still achieves the objectives of the MONOWELL.The expandable liner is cemented in place and then is expanded.Production may take place through the liner and casing.

The previously described embodiments include first drilling and casingthe non-producing wellbore 10A and then drilling and completing theproducing wellbore 10B. Typically the reservoir formation 30 is treateddifferently then the non-producing formations, particularly with respectto the fluids, such as the drilling fluids. However, it should beappreciated that the non-producing formations and the producingformations may be treated essentially the same whereby the monodiameterwellbore 10 extends the entire length of the borehole, i.e., from thesurface 14 to the bottom 15 (the completion target depth) of the well12. This is particularly applicable where the formations aresubstantially all sandstone, such as in Saudi Arabia. The onlydifferential between the non-producing and the producing wellbores willbe the producing wellbore fluids should be compatible and not result indeep reservoir formation damage prohibiting maximum production.

Referring now to FIGS. 19A and B, the above embodiments may be directedto multi-lateral and side-tracked wells. A multi-lateral well may be amodified MONOWELL extending from the junction to the surface. Themulti-lateral is below the junction. FIG. 19A is a schematic of amulti-lateral well 190 having a trunk or upper borehole 192 extending tothe surface 14 and a plurality of branch boreholes 194 a, 194 bextending to the same or different producing zones 30. Upper borehole190 is connected to branch boreholes 194 a, 194 b at a junction 196. Theupper borehole 192 of the multi-lateral well may be a monodiameterwellbore. The lateral boreholes may or may not be monodiameter sectionsbelow junction 196.

FIG. 19B is a schematic of a side-tracked well 200 having a primaryborehole 202 and a side tracked lateral borehole 204. Primary borehole200 may be a new well or an existing well. Primary borehole 202 may be amonodiameter wellbore and the side tracked lateral borehole 204 belowjunction 206 may also be a monodiameter wellbore.

All the previous scenarios that have been discussed above with referenceto non-producing borehole and producing borehole are applicable to othertypes of wells. The section that is called producing can be a waterproduction well, water injection well, miscible gas well,water-alternating with gas well, or any other type well that penetratesthe earth.

Referring now to FIG. 20, there is shown a preferred embodiment of amonodiameter water well of the present invention. FIG. 20 illustratesthe monodiameter wellbore 10 in the completed stage. A conductor casing38 for supporting a wellhead is installed into the earth's surface 14.Both chemical casing 60 and expandable casing 90 have been installed.The combination of the casing chemical and expandable tubulars provide abarrier to formations through which the wellbore 10 extends, such as,for example, problem formations 65. A production tubing string 80extends from the surface 14 to the top of the reservoir 16 of the well.A specialized drilling fluid or chemical casing stabilizes the reservoirby solidifying near the wellbore wall 44 while not penetrating so deepas to damage the formation. Temporary stabilization can be achieved withchemical casing 60 until a metallic or composite casing, such asexpandable casing 90 or possibly conventional casing is run.

Still further, the above embodiments may be directed to a monodiameterwellbore for an artificial lift well, such as a well containing gaslift, jet pump or a submersible pump.

Certain components of the monodiameter well construction have been usedto minimize potential problems and are particularly useful duringmonodiameter well construction due to borehole stability issues orintegrity issues that have to be addressed by non-conventional means.

The monodiameter wellbore may be drilled by various means including apropulsion system (See U.S. Pat. No. 6,296,066), a drilling rig, coiledtubing, pile driving, hydraulic workover, or any other means.Conventional drilling technology may be used. Also, the Anacondadrilling system may be used (See U.S. Pat. No. 6,296,066). Eventually,lasers being developed by the University of Colorado will be used fordrilling. One method of drilling the wellbore includes pipe drive typedevices. In that type of device, the pipe is driven into the formation.For example, jackhammers may be used for drilling the borehole.

Referring now to FIG. 21, there is shown another preferred wellconstruction method to construct the monodiameter borehole using acoiled tubing drilling system 150 to drill a monodiameter wellbore 10having a non-producing borehole 10A extending from the surface 14 to thereservoir barrier 16 and a producing or injection borehole 10B extendingfrom the reservoir barrier 16 to the bottom 15 of the producing orinjection zone 30. See FIG. 14. FIG. 21 shows a section 66 ofnon-producing wellbore 10A being drilled. The coiled tubing drillingsystem 120 includes a power supply 122, a processor 124, and a coiledtubing spool 126 at the surface 14. An injector head unit 128 feeds anddirects coiled tubing 130 from the spool 126 into the borehole beingdrilled for monodiameter wellbore 10. Coiled tubing 130 may be steel orcomposite coiled tubing. The coiled tubing drilling system 120 includesa drilling assembly 150 having a coiled tubing string 130 with a bottomhole assembly 132 connected to its lower end and extending into wellbore10.

The coiled tubing operation 120 utilizes spool 126 to feed the coiledtubing 130 over a guide and through injector 128 and stripper 134. Thecoiled tubing 130 is forced through blowout preventer 136 and into well10 by injector 128. It should be appreciated that blowout preventers andother requisite safety control equipment may be deployed at the surface14 for drilling and completing well 12. Further, it should beappreciated that this embodiment is described for explanatory purposesand that the present invention is not limited to the particular boreholedisclosed, it being appreciated that the present invention may be usedfor various well plans. Operational parameters during the monodiameterwell construction may include drilling and completion with overbalancedconditions, balanced conditions, or underbalanced conditions. Allconditions are met by the apparatus and methods of the presentinvention.

The bottom hole assembly 132 is used for drilling the borehole andincludes various components such as, for example, a propulsion system, apower section, an electronics section, a resistivity tool, a steerableassembly, a gamma ray and inclinometer instrument package, and a bit140. The power section provides the power for rotation of bit 140. Thebit 140 is preferably a SLICKBORE bit with a near bit reamer just aboveit. The resistivity tool determines the formation resistivity around thebottom hole assembly 132. The steerable assembly changes the trajectoryof the borehole and the gamma ray and inclinometer instrument packageevaluates the characteristics of the formation at the bit 140 andprovides early information about the orientation and angle control ofthe bit 140 within the borehole. The power section is typically adownhole motor driven by the drilling fluids passing through the coiledtubing 130. The bottom hole assembly may include a seismic at bit or atesting while drilling tool. See U.S. provisional patent applicationSer. No. 60/381,243 filed May 17, 2002 entitled MWD Formation Tester,hereby incorporated herein by reference. One preferred coiled tubingdrilling system using composite coiled tubing is described in U.S. Pat.No. 6,296,066, hereby incorporated herein by reference. See also SPE60750 “Anaconda: Joint Development Project Leads to Digitally ControlledComposite Coiled Tubing Drilling System”, by Marker, Haukvik, Terry,Paulk, Coats, Wilson, Estep, Farabee, Berning and Song, dated Apr. 5-6,2000.

The bottom hole assembly 132 and bit 140 are shown drilling boreholesection 66 after having drilled and cased the upper section sections ofborehole 10A, such as sections 46, 56 shown in FIG. 14. Drilling fluids144 flow through the flowbore of coiled tubing 130 and back up theannulus 146. Although FIG. 21 illustrates the borehole 10A being casedwith chemical casing 60 and expandable casing 90, the coiled tubingsystem 120 may be used with chemical casing, expandable casing, coiltubing or expandable coil tubing—metallic or composite, or a combinationof chemical casing and expandable casing. It should be appreciated thatthe coiled tubing system may be used with any of the previouslydescribed methods and apparatus.

Referring now to FIG. 22, the wired composite coiled tubing system 160with an integrated MWD/LWD can provide major benefits during theMonowell construction process. The system 160 enables continuous datatransmission during all operational procedures, including proceduresduring which previous conventional data transmission becomes disabled.Furthermore, the transmission rate is greatly increased, resulting inhigh-resolution real-time data from sensors for formation evaluation,directional readings, pressure measurement, tension/weight on bit (WOB),for example. The high-resolution and continuous data transmission helpto solve the potential challenges introduced when drilling amonodiameter well. These challenges include higher ECDs, longer openholeintervals, reduced clearances, and more. The high-quality data also havethe potential to enable more effective use of other new technologiesthat address the geomechanical environment of the well. The wiredcomposite coiled tubing system 160 can identify permeable zones,drilling-induced fractures, and borehole ballooning.

The continuous access to the data, including during trips, can help toprovide early indications of potential problems such as fractureinitiation or borehole instability. The knowledge of the location ofloss zones can improve the effectiveness of chemical treatments toincrease the fracture resistance of the open hole. This knowledge isparticularly useful when drill ahead materials or chemical casingmaterials might have to be used to fill a washed out area before theexpandables are set in a sequential well-construction process. Also, itcan be quite useful when chemical casing can be used to drill longintervals before any casing is set.

In certain situations, management of ECDs can be important to thesuccess of a monodiameter well-construction project. The wired compositecoiled tubing system 160 with a MWD/LWD bottomhole assembly 162 canenhance the ability to manage ECDs. The use of coiled tubing as a drillstring enables continuous circulation while tripping in the hole andallows continuous optimization of drilling fluid properties throughoutthe borehole and active drilling fluids system. Continuous access toannular pressure measurements transmitted through the wired coiledtubing 164 provides useful information about ECDs. With thisinformation, drilling parameters and fluid properties are continuouslyadjusted to remain within the limits of pore pressure and fracturepressure (leakoff). Reductions in pressure resulting from swabbing areeliminated in a smooth, continuous manner by pumping through the coiledtubing drill string 164 while tripping out of the borehole 166.

In addition to the enhanced ability to control the pressure in thewellbore, the system 160 improves the capability to measure porepressure and fracture pressure. If gas influx is observed when the pumpsare stopped or slowed down, the wellbore pressure during the event canbe precisely measured. Likewise, a formation integrity test (FIT) or aLOT can be performed with real-time downhole measurements of thetransient pressure behavior during the test. During a LOT, whichinvolves fracturing of the formation, this high-resolution data improvesand speeds up the interpretation of the test. During a FIT, in whichfracturing is not desired, the high quality of the real-time data canprevent inadvertent fracturing of the formation. Constant PWDmeasurements obtained through the wired composite drilling system 160also give a high degree of control.

These characteristics of the system 160 create the potential to moresafely operate within a narrower window of pore pressure and fracturegradient than is possible with previous technology. While the reservoirhole is drilled, the improved control of pressure in the wellbore, alongwith the potential for enhanced understanding of fracture resistance,reduces the chance of losing drilling fluids to the reservoir. Thisreduction helps prevent production problems associated with such losses.

The wired composite tubing 164 allows the bottomhole assembly to beengineered differently from conventional MWD/LWD systems. Conventionalsystems are self-powered with either batteries or turbines. Batteriesare expensive, hazardous, and must be periodically changed. Turbines arecomplex mechanical devices that are susceptible to erosion and plugging.The mud pulser also suffers from these mechanical failures. The pulseris a slow telemetry method. It can send only a fraction of the sensormeasurements to surface in real time. It can only operate duringcirculation, and therefore, it precludes telemetry during tripping withjointed pipe. This attribute requires that these prior art systems storethe majority of their acquired data in the downhole tool memory. Thisdata can be obtained only by tripping the bottomhole assembly out of thehole and downloading through a cable at surface. These prior art toolsare preconfigured to attempt to optimize the storage and telemetry ofthe data. Large processors are used in the downhole tools to process thesensor signals and raw data to minimize the size of the stored data.Often, the data needed to make decisions is not transmitted in real timeand is left in the tool's memory until the next trip out of the hole.

The wired composite tubing 164 and bottomhole assembly 168 are able toavoid this paradigm due to the embedded wires in the tubing 164. Poweris provided from the surface, eliminating the need for batteries orturbines. All the raw sensor data is transmitted immediately to thesurface in real-time, negating the need for a pulser. These threecomponents typically have the highest rate of failure in conventionalMWD/LWD systems. Because the raw sensor data is processed at surface,large processors or downhole memory are unnecessary. This benefitreduces complexity and eliminates large components on printed circuitboards in the downhole tools that are susceptible to vibration andshock. Quality assurance is easily monitored for the wired compositetubing 164 and bottomhole assembly 168. Most importantly, theavailability of all the data, all the time, allows accurate, real-timedecisions to be made while drilling. FIG. 22A is a cross-section throughthe wired composite coiled tubing 164 showing conductors 170 embedded inthe wall 172 of the composite tubing 164.

A number of factors are important to the performance and reliability ofa horizontal completion. Reservoir characteristics, effective welllength, and near-wellbore conditions determine the inflow performance ofthe completion. Formation characteristics, such as sand uniformity andshaliness, along with the inflow performance, are important to thereliability of completions in unconsolidated formations. More effectiveplacement of the horizontal well in the desired production zone leads toimprovements in performance and reliability.

The formation evaluation sensors in the wired composite tubing andbottomhole assembly consist of an azimuthally focused gamma ray sensorfor bed dip determination and a resistivity sensor with multiple depthsof investigation for optimum wellbore placement. These sensors areparticularly suited for high-inclination wells and geosteering thewellpath across or through the reservoir.

Perforations, expandable screens, mechanical completion shutoffs, andchemical solutions/techniques are more efficiently placed using thewired composite coiled tubing and bottomhole assembly. For amonodiameter/monobore well, the most important goal is to have the mostefficient well-construction process possible with the maximum productionpossible. The wired composite coiled tubing drilling-completion systemsupports this overall philosophy.

The MONOWELL/monodiameter architecture may be used with any type ofreservoir formation and in any environment (deepwater, offshore, orland). The MONOWELL construction may be considered for hard rock,marginal exploration areas, marginal production fields, and infill fielddrilling. All of these areas demand that production be maximized andcost be minimized as much as possible. Before a well is drilled, theattributes of underbalance drilling should also be considered, alongwith how these attributes support the MONOWELL.

Anaconda's propulsion system and wired composite coiled tubing 130allows for it to be set as a casing or completion liner directly acrossthe interval. The propulsion system may or may not be removed from thewell. The wiring within the wall of the composite tubing 130 can be usedto actuate a disconnect at the top of the coil to allow for permanentsetting in the well.

While underbalance drilling can occur using the traditional rig, theoptimum solution for the MONOWELL is to integrate the wired compositecoiled tubing with underbalance drilling. Using underbalance devices,such as a trip valve that allows the bottomhole assembly to be retrievedwithout killing the well, can allow real-time well testing by flowingthe well to a separation vessel. Also, mud-logging data, downholewell-testing data, downhole pressure, and lithologies may be collectedfrom the wired composite coiled tubing and bottomhole assembly drillingsystem for data acquisition and analyses. This integrated underbalancedwired composite drilling system is an optimum production drilling systemfor consideration when constructing a MONOWELL.

Depending on the MONOWELL's inner wellbore diameters, drillinghydraulics, and production requirements, differential stickingtolerances can be very limited. Underbalance drilling can help reduce,if not eliminate, differential sticking, allowing smaller diameters tobe constructed.

In a still another preferred method and apparatus of the presentinvention, the coil tubing can be utilized as the casing or it can beexpanded and used as the casing. Additional details are set forth inU.S. patent application Ser. No. 10/016,786 filed Dec. 10, 2001 entitled“Casing While Drilling”, now U.S. Pat. No. 6,722,451, herebyincorporated herein by reference. See also IADC/SPE 59126 “SimultaneousDrill and Case Technology—Case Histories, Status and Options for FurtherDevelopment”, by Hahn, Van Gestel, Frohlich, and Stewart, dated Feb.23-25, 2000.

There are shown specific embodiments of the present invention with theunderstanding that the present disclosure is to be considered anexemplification of the principles of the invention, and is not intendedto limit the invention to that illustrated and described herein. Variousdimensions, sizes, quantities, volumes, rates, and other numericalparameters and numbers have been used for purposes of illustration andexemplification of the principles of the invention, and is not intendedto limit the invention to the numerical parameters and numbersillustrated, described or otherwise stated herein.

While a preferred embodiment of the invention has been shown anddescribed, modifications thereof can be made by one skilled in the artwithout departing from the spirit of the invention.

1. A method for achieving a monodiameter wellbore extending throughvarious formations, the method comprising: extending a work string intothe wellbore, the work string having a bottomhole assembly; flowingdrilling fluids through the work string and bottomhole assembly;drilling the wellbore using an extended gauge drilling member tominimize spiraling of the wellbore; sending to the surface real-timedownhole information from a measurement while drilling tool, a loggingwhile drilling tool, and one or more sensors in the extended gaugedrilling member tool; altering the direction of drilling based on thereal-time downhole information using a directional steering assembly;and chemically casing the wellbore.
 2. The method of claim 1 whereinextended gauge drilling member includes an energy balanced bit.
 3. Themethod of claim 1 wherein the directional steering assembly includes arotary steerable assembly associated with the extended gauge drillingmember.
 4. The method of claim 1 further including a downhole motormatched to the extended gauge drilling member.
 5. The method of claim 1further including circulating drilling fluids which are matched to theformations.
 6. The method of claim 5 wherein the drilling fluids use amembrane efficient mud system which allows the drilling of a consistenttight wellbore.
 7. The method of claim 6 wherein the membrane efficientmud system is a water or synthetic based system.
 8. The method of claim7 wherein the drilling fluids produce a mud cake that effectivelycontrols hydraulic pressure, chemical differences, and electricaldifferences in the formation.
 9. The method of claim 1 further includingflowing a spottable material through the wellbore.
 10. The method ofclaim 1 further including installing expandable casing in the wellbore.11. The method of claim 10 further including flowing a sealingcomposition between the expandable casing and a wall of the wellbore.